Method of developing a subsurface freeze zone using formation fractures

ABSTRACT

A method for lowering the temperature of a portion of a subsurface formation is provided. Preferably, the formation is an oil shale formation. The method includes the step of injecting a cooling fluid under pressure into a wellbore, with the wellbore having been completed at or below a depth of the subsurface formation. The wellbore has an elongated tubular member for receiving the cooling fluid and for conveying it downhole to the subsurface formation. The wellbore also has an expansion valve in fluid communication with the tubular member through which the cooling fluid flows. The method then includes the steps of injecting a cooling fluid under pressure into the wellbore, and expanding the cooling fluid across the first expansion valve. In this way, the temperature of the cooling fluid is reduced. The temperature of the surrounding formation is likewise reduced through thermal conduction and convection.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional application60/851,543 which was filed on Oct. 13, 2006. The provisional applicationis incorporated herein in its entirety by reference.

This application is also related to co-pending, concurrently filed, andcommonly assigned U.S. patent application Ser. No. 11/973,764, filedOct. 10, 2007. entitled “Improved Method of Developing Subsurface FreezeZone,” which claims the benefit of U.S. Provisional Patent ApplicationSer. No. 60/851,543, filed Oct. 13. 2006.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to the field of hydrocarbon recovery fromsubsurface formations. More specifically, the present invention relatesto the in situ recovery of hydrocarbon fluids from organic-rich rockformations including, for example, oil shale formations, coal formationsand tar sands formations. The present invention also relates to methodsfor lowering the temperature of a subsurface formation, and containingfluids within a shale oil development area through the reduction intemperature of a selected portion of a subsurface formation.

2. Background of the Invention

Certain geological formations are known to contain an organic matterknown as “kerogen.” Kerogen is a solid, carbonaceous material. Whenkerogen is imbedded in rock formations, the mixture is referred to asoil shale. This is true whether or not the mineral is, in fact,technically shale, that is, a rock formed from compacted clay.

Kerogen is subject to decomposing upon exposure to heat over a period oftime. Upon heating, kerogen molecularly decomposes to produce oil, gas,and carbonaceous coke. Small amounts of water may also be generated. Theoil, gas and water fluids become mobile within the rock matrix, whilethe carbonaceous coke remains essentially immobile.

Oil shale formations are found in various areas world-wide, includingthe United States. Oil shale formations tend to reside at relativelyshallow depths. In the United States, oil shale is most notably found inWyoming, Colo., and Utah. These formations are often characterized bylimited permeability. Some consider oil shale formations to behydrocarbon deposits which have not yet experienced the years of heatand pressure thought to be required to create conventional oil and gasreserves.

The decomposition rate of kerogen to produce mobile hydrocarbons istemperature dependent. Temperatures generally in excess of 270° C. (518°F.) over the course of many months may be required for substantialconversion. At higher temperatures substantial conversion may occurwithin shorter times. When kerogen is heated, chemical reactions breakthe larger molecules forming the solid kerogen into smaller molecules ofoil and gas. The thermal conversion process is referred to as pyrolysisor retorting.

Attempts have been made for many years to extract oil from oil shaleformations. Near-surface oil shales have been mined and retorted at thesurface for over a century. In 1862, James Young began processingScottish oil shales. The industry lasted for about 100 years. Commercialoil shale retorting through surface mining has been conducted in othercountries as well such as Australia, Brazil, China, Estonia, France,Russia, South Africa, Spain, and Sweden. However, the practice has beenmostly discontinued in recent years because it proved to be uneconomicalor because of environmental constraints on spent shale disposal. (See T.F. Yen, and G. V. Chilingarian, “Oil Shale,” Amsterdam, Elsevier, p.292, the entire disclosure of which is incorporated herein byreference.) Further, surface retorting requires mining of the oil shale,which limits application to very shallow formations.

In the United States, the existence of oil shale deposits innorthwestern Colorado has been known since the early 1900's. Whileresearch projects have been conducted in this area from time to time, noserious commercial development has been undertaken. Most research on oilshale production has been carried out in the latter half of the 1900's.The majority of this research was on shale oil geology, geochemistry,and retorting in surface facilities.

In 1947, U.S. Pat. No. 2,732,195 issued to Ljungstrom. That patent,entitled “Method of Treating Oil Shale and Recovery of Oil and OtherMineral Products Therefrom,” proposed the application of heat at hightemperatures to the oil shale formation in situ to distill and producehydrocarbons. The '195 Ljungstrom patent is incorporated herein byreference.

Ljungstrom coined the phrase “heat supply channels” to describe boreholes drilled into the formation. The bore holes received an electricalheat conductor which transferred heat to the surrounding oil shale.Thus, the heat supply channels served as heat injection wells. Theelectrical heating elements in the heat injection wells were placedwithin sand or cement or other heat-conductive material to permit theheat injection wells to transmit heat into the surrounding oil shalewhile preventing the inflow of fluid. According to Ljungstrom, the“aggregate” was heated to between 500° and 1,000° C. in someapplications.

Along with the heat injection wells, fluid producing wells were alsocompleted in near proximity to the heat injection wells. As kerogen waspyrolyzed upon heat conduction into the rock matrix, the resulting oiland gas would be recovered through the adjacent production wells.

Ljungstrom applied his approach of thermal conduction from heatedwellbores through the Swedish Shale Oil Company. A full scale plant wasdeveloped that operated from 1944 into the 1950's. (See G. Salamonsson,“The Ljungstrom In Situ Method for Shale-Oil Recovery,” 2^(nd) Oil Shaleand Cannel Coal Conference, v. 2, Glasgow, Scotland, Institute ofPetroleum, London, p. 260-280 (1951), the entire disclosure of which isincorporated herein by reference.)

Additional in situ methods have been proposed. These methods generallyinvolve the injection of heat and/or solvent into a subsurface oilshale. Heat may be in the form of heated methane (see U.S. Pat. No.3,241,611 to J. L. Dougan), flue gas, or superheated steam (see U.S.Pat. No. 3,400,762 to D. W. Peacock). Heat may also be in the form ofelectric resistive heating, dielectric heating, radio frequency (RF)heating (U.S. Pat. No. 4,140,180, assigned to the ITT Research Institutein Chicago, Ill.) or oxidant injection to support in situ combustion. Insome instances, artificial permeability has been created in the matrixto aid the movement of pyrolyzed fluids. Permeability generation methodsinclude mining, rubblization, hydraulic fracturing (see U.S. Pat. No.3,468,376 to M. L. Slusser and U.S. Pat. No. 3,513,914 to J. V. Vogel),explosive fracturing (see U.S. Pat. No. 1,422,204 to W. W. Hoover, etal.), heat fracturing (see U.S. Pat. No. 3,284,281 to R. W. Thomas), andsteam fracturing (see U.S. Pat. No. 2,952,450 to H. Purre).

In 1989, U.S. Pat. No. 4,886,118 issued to Shell Oil Company, the entiredisclosure of which is incorporated herein by reference. That patent,entitled “Conductively Heating a Subterranean Oil Shale to CreatePermeability and Subsequently Produce Oil,” declared that “[c]ontrary tothe implications of . . . prior teachings and beliefs . . . thepresently described conductive heating process is economically feasiblefor use even in a substantially impermeable subterranean oil shale.”(col. 6, ln. 50-54). Despite this declaration, it is noted that few, ifany, commercial in situ shale oil operations have occurred other thanLjungstrom's application. The '118 patent proposed controlling the rateof heat conduction within the rock surrounding each heat injection wellto provide a uniform heat front.

Additional history behind oil shale retorting and shale oil recovery canbe found in co-owned patent publication WO 2005/010320 entitled “Methodsof Treating a Subterranean Formation to Convert Organic Matter intoProducible Hydrocarbons,” and in patent publication WO 2005/045192entitled “Hydrocarbon Recovery from Impermeable Oil Shales.” TheBackground and technical disclosures of these two patent publicationsare incorporated herein by reference.

A need exists for improved processes for the production of shale oil. Inaddition, a need exists for improved methods for containing water andproduction fluids within a hydrocarbon development area. Still further,a need exists for an improved freeze well that uses formation fractures.

SUMMARY OF THE INVENTION

The methods described herein have various benefits in improving thecooling efficiency of certain prior art methods. In various embodiments,such benefits may include the reduction of cooling losses to theoverburden, reducing the amount of fluid needed to be circulated, orspeeding the formation of an impermeable freeze zone.

A method for lowering the temperature of a subsurface formation isprovided herein. This method includes the step of injecting a coolingfluid under pressure into a wellbore. The cooling fluid comprises aslurry having particles of frozen material. The cooling fluid iscirculated across the formation in order to lower the temperature of atleast a portion of the formation. Preferably, the temperature is loweredto a point below the freezing point of water.

Use of a slurry can have the benefit of significantly increasing the“cold energy” carried by the cooling fluid per mass of fluid. Moreover,a slurry can maintain a relatively constant temperature even as it loses“cold energy” due to the latent heat of fusion of the solids.

The wellbore is completed at or below a depth of the subsurfaceformation. The wellbore has a bore formed through the subsurfaceformation that defines a diameter. In this case no downhole expansionvalve is required. Use of a slurry can have the extra benefit ofremoving or reducing the need for insulation between the upward anddownward flows since the slurry can be maintained at a relativelyconstant temperature as long as frozen solids are still present.

It is preferred that the steps for the method be repeated for aplurality of wellbores. In one aspect, at least ten adjacent freezewells are completed. The cooling fluid is circulated within the tenadjacent freeze wells in order to form a flow barrier in the subsurfaceformation. In one aspect, the integrity of the flow barrier is monitoredby analyzing compositions of fluid samples taken from wells formedoutside of the flow barrier.

In one aspect of this additional embodiment, the wellbore includes anelongated tubular member that receives the cooling fluid en route to thesubsurface formation. The elongated tubular member may be a U-tube. Inthis instance, the method further includes circulating the cooling fluidinto the U-tube, to the completion depth, and back to the surface.

The wellbore may further comprise an annular region formed between theelongated tubular member and the diameter of the wellbore. In thisinstance, the method may further include circulating the fluid into thetubular member, to the completion depth, and back up the wellborethrough the annular region.

Various cooling fluids may be used. In one aspect, the cooling fluid isa partially frozen salt-water mixture. The salt in the salt-watermixture may be, for example, NaCl or CaCl₂. The cooling fluid mayalternately define a partially frozen alcohol-water mixture. The alcoholmay be, for example, methanol or ethanol.

In another aspect, the cooling fluid may define a partially frozenglycol-water mixture. The glycol may be, for example, MEG, DEG, orpropylene glycol. In another aspect, the cooling fluid may define ahydrocarbon mixture comprised of greater than 50 mol. percent carbonmolecules of C₇, C₈, C₉, C₁₀, C₁₁, C₁₂, C₁₃, C₁₄, or mixtures thereof.

The particles of frozen material used in this additional embodiment maybe less than 50 microns in size. Some or all of the particles may beless than 10 microns in size.

Preferably, the cooling fluid is at a temperature of about −20° F. to−120° F. after passing through the first expansion valve. Morepreferably, the cooling fluid is at a temperature of about −20° F. to−80° F. after passing through the first expansion valve. More preferablystill, the cooling fluid is at a temperature of about −30° F. to −60° F.after passing through the first expansion valve.

Preferably, the subsurface formation holds in situ water. Further, thecooling fluid cools the subsurface formation to a sufficient extent tofreeze at least a portion of the in situ water. In one aspect, themethod further includes the step of injecting low salinity water into atleast a portion of the subsurface formation to reduce the naturalsalinity of the in situ water and to raise the freezing temperature ofthe in situ water.

In some instance, a single downhole expansion valve is used. In thisinstance, the cooling fluid is preferably at a pressure of about 100psia to 2,000 psia before passing through the expansion valve. Morepreferably the cooling fluid is at a pressure of about 200 psia to 800psia.

For the case of dual downhole expansion valves, preferably the coolingfluid is at a pressure of about 800 psia to 4,000 psia before passingthrough the first expansion valve, about 100 psia to about 800 psiaafter passing through the first expansion valve, and about 25 to 100psia after passing through the second expansion valve. More preferably,the cooling fluid is at a pressure of about 800 psia to 2,000 psiabefore passing through the first expansion valve, about 100 psia toabout 500 psia after passing through the first expansion valve, andabout 25 psia to about 100 psia after passing through the secondexpansion valve.

Also disclosed herein is a method of lowering the temperature of asubsurface formation. The method may include the steps of completing afirst injection well, and also completing a second injection welladjacent the first injection well. The method also includes injecting afracturing fluid into the first injection well so as to form a fractureat a depth of the subsurface formation. In this way, fluid communicationis established between the first and second injection wells.

The method also includes injecting a cooling fluid under pressure intothe first injection well and into the fracture. This serves to lower thetemperature of the subsurface formation. The method further includescirculating at least a portion of the cooling fluid back up through thesecond injection well.

In this method, the geomechanical conditions are chosen such that thefracture is substantially vertical. The well from which the fracture isformed may by substantially vertical or substantially horizontal.

The first injection well preferably comprises an elongated tubularmember that receives the cooling fluid en route to the subsurfaceformation. The first injection well may further comprise an expansionvalve in fluid communication with the tubular member through which thecooling fluid flows to cool the subsurface formation. The expansionvalve may be positioned at a selected point along the wellbore. In oneinstance, the expansion valve is positioned along the tubular memberproximate an upper depth of the subsurface formation.

Once again, various cooling fluids may be used. In one aspect, thecooling fluid is a partially frozen salt-water mixture. The salt in thesalt-water mixture may be, for example, NaCl or CaCl₂. The cooling fluidmay alternately define a partially frozen alcohol-water mixture. Thealcohol may be, for example, methanol or ethanol.

In another aspect, the cooling fluid may define a partially frozenglycol-water mixture. The glycol may be, for example, MEG, DEG, orpropylene glycol. In another aspect, the cooling fluid may define ahydrocarbon mixture comprised of greater than 50 mol. percent carbonmolecules of C₇, C₈, C₉, C₁₀, C₁₁, C₁₂, C₁₃, C₁₄, or mixtures thereof.

In one aspect, the cooling fluid is a slurry that comprises particles offrozen material. The particles within the cooling fluid may be formedthrough a process of mechanical grinding. The particles may have acomposition that is different than the cooling fluid. The cooling fluidmay be a mixture with a composition that is close to the eutecticcomposition.

In one aspect, the composition of the particles has a freezingtemperature that is higher than the cooling fluid. In this instance, theparticles are formed by rapidly cooling the cooling fluid below thefreezing temperature of the particles, but not below the freezingtemperature of the cooling fluid. In another aspect, the particles areseeded into the cooling fluid in a frozen state. The particles maycomprise a biphasic material having an external portion and an internalportion such that the external portion has a higher freezing temperaturethan the internal portion.

For single phase cooling fluids, the fracturing fluid preferablycomprises a proppant to prop the formation. For slurry cooling fluids,the fracturing fluid preferably does not contain a proppant or containsproppant particles which are at least 8 times that of the average sizeof the slurry particles.

Yet another method of lowering the temperature of a subsurface formationis disclosed herein. This method includes the step of completing a wellhaving fluid communication with the subsurface formation at both a firstdepth and a second lower depth. A fracturing fluid is then injected intothe well so as to form a substantially vertical fracture at a depth ofthe subsurface formation. In this way, fluid communication is providedbetween the first and second depths in the well. Then, a cooling fluidis circulated under pressure through the well and into the fractures.The cooling fluid flows from one depth to the other, thereby loweringthe temperature of the subsurface formation.

The well may be completed substantially vertically within the subsurfaceformation. Alternatively, the well may be completed substantiallyhorizontally within the subsurface formation. The fracture fluid may ormay not contain proppant.

Still another method for lowering the temperature of a subsurfaceformation is provided herein. The method comprises injecting a coolingfluid at a first temperature into a wellbore. The wellbore is completedat or below a depth of the subsurface formation. The method alsoincludes lowering the temperature of the cooling fluid after it hasentered the wellbore. The cooling fluid is passed through the wellboreat a depth of the subsurface formation at the lower temperature. Fromthere, the cooling fluid is circulated back to the surface.

The wellbore in this instance may comprise an elongated tubular memberthat receives the cooling fluid en route to the subsurface formation.The wellbore may further comprise a first expansion valve in fluidcommunication with the tubular member through which the cooling fluidflows. The expansion valve serves to cool the cooling fluid to the lowertemperature.

A cooling wellbore is also disclosed herein. The cooling wellbore is forthe purpose of lowering the temperature of a subsurface formation. Thewellbore is completed at or below a depth of the subsurface formation,and in one aspect includes an elongated tubular member, and a firstexpansion valve. The first expansion valve is in fluid communicationwith the elongated tubular member. A cooling fluid is directed throughthe elongated tubular member and the first expansion valve in order tocool the subsurface formation.

In one aspect, the elongated tubular member is a U-tube. The firstexpansion valve may be positioned in the tubular member above an upperdepth of the subsurface formation. Alternatively, the first expansionvalve may be positioned in the tubular member proximate a lower depth ofthe subsurface formation. Alternatively still, the first expansion valvemay be positioned in the tubular member proximate an upper depth of thesubsurface formation.

In one embodiment, the wellbore further comprises an annular regionformed between the elongated tubular member and a diameter of thewellbore. The cooling fluid may be circulated through the tubular memberalong the subsurface formation, and then back up the wellbore throughthe surrounding annular region.

In another embodiment, the elongated tubular member is a U-tubecomprising a downward portion through which the cooling fluid flows tothe subsurface formation, and an upward portion through which thecooling fluid flows back to the surface. Insulation may be placed alongall or a portion of the U-tube to reduce cross heat exchange between theupward and downward flows. The cooling wellbore may further include asecond expansion valve. The cooling fluid flows through the firstexpansion valve upon or before reaching the depth of the subsurfaceformation. The cooling fluid further flows through the second expansionvalve at or after reaching the depth of the subsurface formation.

Various cooling fluids may be used. In one aspect, the cooling fluidcomprises a liquid that wholly or partially vaporizes upon passingthrough the first expansion valve. In another aspect, the cooling fluidcomprises a gas. The cooling fluid may be injected in a gaseous state,and remain in a substantially gaseous state when passed through thefirst expansion valve. Alternatively, the cooling fluid may be injectedin a gaseous state, but a portion of the cooling fluid condenses from agas to a liquid state as the cooling fluid is passed through the firstexpansion valve.

The injected cooling fluid may comprise at least of 50 mol. percent ofpropane, propylene, ethane, ethylene, or a mixture thereof.Alternatively, the cooling fluid may comprise at least of 80 mol.percent of propane, propylene, ethane, ethylene, isobutane, or a mixturethereof.

Alternatively, the injected cooling fluid may comprise at least of 50mol. percent of a halogenated hydrocarbon. Alternatively, the coolingfluid may comprise at least of 80 mol. percent of a halogenatedhydrocarbon.

The cooling fluid may be chilled prior to injection into the tubularmember. For instance, the cooling fluid may be chilled below ambient airtemperature prior to injection into the tubular member. In any instance,the cooling fluid may be injected into the subsurface formation at acontrolled rate such that the cooling fluid flows through the firstexpansion valve and adjacent the subsurface formation, and then leavesthe subsurface formation with no more than 20 wt. % in a liquid state.Alternatively, the cooling fluid may be injected into the subsurfaceformation at a controlled rate such that the cooling fluid flows throughthe first expansion valve and adjacent the subsurface formation, andthen leaves the subsurface formation with no more than 5 wt. % in aliquid state.

The cooling wellbore may be placed at various positions relative to theshale oil development area. Preferably, one or more wellbores are formedoutside of or along the periphery of the area under shale oildevelopment.

Finally, a method for forming a freeze wall within a subsurfaceformation is provided. In one aspect, the method includes determining adirection of least principal stress within the subsurface formation, andthen forming a plurality of cooling wellbores along the directionperpendicular to said direction of least principal stress. The methodalso includes injecting a fracturing fluid into at least some of thecooling wellbores so as to form substantially vertical fractures at adepth of the subsurface formation. In this way, fluid communication isprovided between the cooling wellbores.

In accordance with the method for forming a freeze wall, certain of thecooling wellbores are designated as injectors and certain of the coolingwellbores are designated as producers. The method includes injecting acooling fluid under pressure into the injectors and into the fracturesso as to lower the temperature of the subsurface formation. The methodthen includes circulating at least a portion of the cooling fluid backup through the producers.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the features of the present invention can be better understood,certain drawings, graphs and flow charts are appended hereto. It is tobe noted, however, that the drawings illustrate only selectedembodiments of the inventions and are therefore not to be consideredlimiting of scope, for the inventions may admit to other equallyeffective embodiments and applications.

FIG. 1 is a cross-sectional view of an illustrative subsurface area. Thesubsurface area includes an organic-rich rock matrix that defines asubsurface formation.

FIG. 2 is a flow chart demonstrating a general method of in situ thermalrecovery of oil and gas from an organic-rich rock formation, in oneembodiment.

FIG. 3 is cross-sectional side view of an oil shale developmentindicating ground water flow.

FIG. 4 provides a plan view of an illustrative heater well arrangementusing more than one layer of heater wells.

FIG. 5 is a bar chart comparing one ton of Green River oil shale beforeand after a simulated in situ, retorting process.

FIG. 6 is a cross-sectional view of a portion of a hydrocarbondevelopment area. An illustrative organic-rich rock formation is shownbeneath the surface. A plurality of freeze wells are positioned aroundperipheral portions of the hydrocarbon development area.

FIG. 7 is a cross-sectional view of a wellbore for a freeze well, in oneembodiment. The wellbore is completed at the level of an organic-richrock formation.

FIG. 8 is a cross-sectional view of an expansion valve, in oneembodiment. This is an enlarged view of the expansion valve used in thewellbore of FIG. 7.

FIG. 9 is a cross-sectional view of an alternate arrangement for anexpansion valve as might be used in the wellbore of a freeze well.

FIG. 10 is a cross-sectional view of a wellbore for a freeze well, in analternate embodiment. In this wellbore, two expansion valves are placedproximate the level of an organic-rich rock formation. The expansionvalves used are as depicted in FIG. 9.

FIG. 11 is a cross-sectional view of a wellbore for a freeze well in yetan additional embodiment. Again, two expansion valves are placedproximate the level of an organic-rich rock formation. One valve isalong the inner diameter of an elongated tubular member, while the otheris along the outer diameter of the elongated tubular member.

FIG. 12 is a cross-sectional view of a wellbore for a freeze well in yetan additional embodiment. Here, the elongated tubular member is a U-tubefor circulating the cooling fluid back up to the surface. An expansionvalve is placed along the inner diameter of the U-tube.

FIG. 13 is a perspective view of a freeze wall being formed in asubsurface formation. A cooling fluid is being circulated between twowells, one of which is injecting the cooling fluid and the other ofwhich is receiving the cooling fluid via a fracture in the formation.

FIG. 14 is a cross-sectional view of a dually completed wellbore. Thewellbore forms a freeze well in an alternate embodiment.

FIG. 15 is a process flow diagram of exemplary surface processingfacilities for a subsurface formation development.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

Definitions

As used herein, the term “hydrocarbon(s)” refers to organic materialwith molecular structures containing carbon bonded to hydrogen.Hydrocarbons may also include other elements, such as, but not limitedto, halogens, metallic elements, nitrogen, oxygen, and/or sulfur.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon ormixtures of hydrocarbons that are gases or liquids. For example,hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbonsthat are gases or liquids at formation conditions, at processingconditions or at ambient conditions (15° C. and 1 atm pressure).Hydrocarbon fluids may include, for example, oil, natural gas, coalbedmethane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product ofcoal, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, the terms “produced fluids” and “production fluids”refer to liquids and/or gases removed from a subsurface formation,including, for example, an organic-rich rock formation. Produced fluidsmay include both hydrocarbon fluids and non-hydrocarbon fluids.Production fluids may include, but are not limited to, pyrolyzed shaleoil, synthesis gas, a pyrolysis product of coal, carbon dioxide,hydrogen sulfide and water (including steam). Produced fluids mayinclude both hydrocarbon fluids and non-hydrocarbon fluids.

As used herein, the term “condensable hydrocarbons” means thosehydrocarbons that condense at 25° C. and one atmosphere absolutepressure. Condensable hydrocarbons may include a mixture of hydrocarbonshaving carbon numbers greater than 4.

As used herein, the term “non-condensable hydrocarbons” means thosehydrocarbons that do not condense at 25° C. and one atmosphere absolutepressure. Non-condensable hydrocarbons may include hydrocarbons havingcarbon numbers less than 5.

As used herein, the term “heavy hydrocarbons” refers to hydrocarbonfluids that are highly viscous at ambient conditions (15° C. and 1 atmpressure). Heavy hydrocarbons may include highly viscous hydrocarbonfluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons mayinclude carbon and hydrogen, as well as smaller concentrations ofsulfur, oxygen, and nitrogen. Additional elements may also be present inheavy hydrocarbons in trace amounts. Heavy hydrocarbons may beclassified by API gravity. Heavy hydrocarbons generally have an APIgravity below about 20 degrees. Heavy oil, for example, generally has anAPI gravity of about 10-20 degrees, whereas tar generally has an APIgravity below about 10 degrees. The viscosity of heavy hydrocarbons isgenerally greater than about 100 centipoise at 15° C.

As used herein, the term “solid hydrocarbons” refers to any hydrocarbonmaterial that is found naturally in substantially solid form atformation conditions. Non-limiting examples include kerogen, coal,shungites, asphaltites, and natural mineral waxes.

As used herein, the term “formation hydrocarbons” refers to both heavyhydrocarbons and solid hydrocarbons that are contained in anorganic-rich rock formation. Formation hydrocarbons may be, but are notlimited to, kerogen, oil shale, coal, bitumen, tar, natural mineralwaxes, and asphaltites.

As used herein, the term “tar” refers to a viscous hydrocarbon thatgenerally has a viscosity greater than about 10,000 centipoise at 15° C.The specific gravity of tar generally is greater than 1.000. Tar mayhave an API gravity less than 10 degrees. “Tar sands” refers to aformation that has tar in it.

As used herein, the term “kerogen” refers to a solid, insolublehydrocarbon that principally contains carbon, hydrogen, nitrogen,oxygen, and sulfur. Oil shale contains kerogen.

As used herein, the term “bitumen” refers to a non-crystalline solid orviscous hydrocarbon material that is substantially soluble in carbondisulfide.

As used herein, the term “oil” refers to a hydrocarbon fluid containinga mixture of condensable hydrocarbons.

As used herein, the term “subsurface” refers to geologic strataoccurring below the earth's surface.

As used herein, the term “hydrocarbon-rich formation” refers to anyformation that contains more than trace amounts of hydrocarbons. Forexample, a hydrocarbon-rich formation may include portions that containhydrocarbons at a level of greater than 5 volume percent. Thehydrocarbons located in a hydrocarbon-rich formation may include, forexample, oil, natural gas, heavy hydrocarbons, and solid hydrocarbons.

As used herein, the term “organic-rich rock” refers to any rock matrixholding solid hydrocarbons and/or heavy hydrocarbons. Rock matrices mayinclude, but are not limited to, sedimentary rocks, shales, siltstones,sands, silicilytes, carbonates, and diatomites.

As used herein, the term “formation” refers to any finite subsurfaceregion. The formation may contain one or more hydrocarbon-containinglayers, one or more non-hydrocarbon containing layers, an overburden,and/or an underburden of any subsurface geologic formation. An“overburden” and/or an “underburden” is geological material above orbelow the formation of interest. An overburden or underburden mayinclude one or more different types of substantially impermeablematerials. For example, overburden and/or underburden may include rock,shale, mudstone, or wet/tight carbonate (i.e., an impermeable carbonatewithout hydrocarbons). An overburden and/or an underburden may include ahydrocarbon-containing layer that is relatively impermeable. In somecases, the overburden and/or underburden may be permeable.

As used herein, the term “organic-rich rock formation” refers to anyformation containing organic-rich rock. Organic-rich rock formationsinclude, for example, oil shale formations, coal formations, and tarsands formations.

As used herein, the term “pyrolysis” refers to the breaking of chemicalbonds through the application of heat. For example, pyrolysis mayinclude transforming a compound into one or more other substances byheat alone or by heat in combination with an oxidant. Pyrolysis mayinclude modifying the nature of the compound by addition of hydrogenatoms which may be obtained from molecular hydrogen, water, carbondioxide, or carbon monoxide. Heat may be transferred to a section of theformation to cause pyrolysis.

As used herein, the term “water-soluble minerals” refers to mineralsthat are soluble in water. Water-soluble minerals include, for example,nahcolite (sodium bicarbonate), soda ash (sodium carbonate), dawsonite(NaAl(CO₃)(OH)₂), or combinations thereof. Substantial solubility mayrequire heated water and/or a non-neutral pH solution.

As used herein, the term “formation water-soluble minerals” refers towater-soluble minerals that are found naturally in a formation.

As used herein, the term “migratory contaminant species” refers tospecies that are both soluble or moveable in water or an aqueous fluid,and are considered to be potentially harmful or of concern to humanhealth or the environment. Migratory contaminant species may includeinorganic and organic contaminants. Organic contaminants may includesaturated hydrocarbons, aromatic hydrocarbons, and oxygenatedhydrocarbons. Inorganic contaminants may include metal contaminants, andionic contaminants of various types that may significantly alter pH orthe formation fluid chemistry. Aromatic hydrocarbons may include, forexample, benzene, toluene, xylene, ethylbenzene, and tri-methylbenzene,and various types of polyaromatic hydrocarbons such as anthracenes,naphthalenes, chrysenes and pyrenes. Oxygenated hydrocarbons mayinclude, for example, alcohols, ketones, phenols, and organic acids suchas carboxylic acid. Metal contaminants may include, for example,arsenic, boron, chromium, cobalt, molybdenum, mercury, selenium, lead,vanadium, nickel or zinc. Ionic contaminants include, for example,sulfides, sulfates, chlorides, fluorides, ammonia, nitrates, calcium,iron, magnesium, potassium, lithium, boron, and strontium.

As used herein, the term “cracking” refers to a process involvingdecomposition and molecular recombination of organic compounds toproduce a greater number of molecules than were initially present. Incracking, a series of reactions take place accompanied by a transfer ofhydrogen atoms between molecules. For example, naphtha may undergo athermal cracking reaction to form ethene and H₂ among other molecules.

As used herein, the term “sequestration” refers to the storing of afluid that is a by-product of a process rather than discharging thefluid to the atmosphere or open environment.

As used herein, the term “subsidence” refers to a downward movement of asurface relative to an initial elevation of the surface.

As used herein, the term “thickness” of a layer refers to the distancebetween the upper and lower boundaries of a cross section of a layer,wherein the distance is measured normal to the average tilt of the crosssection.

As used herein, the term “thermal fracture” refers to fractures createdin a formation caused directly or indirectly by expansion or contractionof a portion of the formation and/or fluids within the formation, whichin turn is caused by increasing/decreasing the temperature of theformation and/or fluids within the formation, and/or byincreasing/decreasing a pressure of fluids within the formation due toheating. Thermal fractures may propagate into or form in neighboringregions significantly cooler than the heated zone.

As used herein, the term “hydraulic fracture” refers to a fracture atleast partially propagated into a formation, wherein the fracture iscreated through injection of pressurized fluids into the formation. Thefracture may be artificially held open by injection of a proppantmaterial. Hydraulic fractures may be substantially horizontal inorientation, substantially vertical in orientation, or oriented alongany other plane.

As used herein, the term “wellbore” refers to a hole in the subsurfacemade by drilling or insertion of a conduit into the subsurface. Awellbore may have a substantially circular cross section, or othercross-sectional shapes (e.g., circles, ovals, squares, rectangles,triangles, slits, or other regular or irregular shapes). As used herein,the term “well”, when referring to an opening in the formation, may beused interchangeably with the term “wellbore.”

DESCRIPTION OF SPECIFIC EMBODIMENTS

The inventions described herein are in connection with certain specificembodiments. However, to the extent that the following detaileddescription is specific to a particular embodiment or a particular use,such is intended to be illustrative only and is not to be construed aslimiting the scope of the inventions.

As discussed herein, some embodiments of the inventions include or haveapplication related to an in situ method of recovering naturalresources. The natural resources may be recovered from an organic-richrock formation, including, for example, an oil shale formation. Theorganic-rich rock formation may include formation hydrocarbons,including, for example, kerogen, coal, and heavy hydrocarbons. In someembodiments of the inventions the natural resources may includehydrocarbon fluids, including, for example, products of the pyrolysis offormation hydrocarbons such as oil shale. In some embodiments of theinventions the natural resources may also include water-solubleminerals, including, for example, nahcolite (sodium bicarbonate, or2NaHCO₃), soda ash (sodium carbonate, or Na₂CO₃) and dawsonite(NaAl(CO₃)(OH)₂).

FIG. 1 presents a perspective view of an illustrative oil shaledevelopment area 10. A surface 12 of the development area 10 isindicated. Below the surface is an organic-rich rock formation 16. Theillustrative subsurface formation 16 contains formation hydrocarbons(such as, for example, kerogen) and possibly valuable water-solubleminerals (such as, for example, nahcolite). It is understood that therepresentative formation 16 may be any organic-rich rock formation,including a rock matrix containing coal or tar sands, for example. Inaddition, the rock matrix making up the formation 16 may be permeable,semi-permeable or non-permeable. The present inventions are particularlyadvantageous in oil shale development areas initially having verylimited or effectively no fluid permeability.

In order to access formation 16 and recover natural resources therefrom,a plurality of wellbores is formed. Wellbores are shown at 14 in FIG. 1.The representative wellbores 14 are essentially vertical in orientationrelative to the surface 12. However, it is understood that some or allof the wellbores 14 could deviate into an obtuse or even horizontalorientation. In the arrangement of FIG. 1, each of the wellbores 14 iscompleted in the oil shale formation 16. The completions may be eitheropen or cased hole. The well completions may also include propped orunpropped hydraulic fractures emanating therefrom.

In the view of FIG. 1, only seven wellbores 14 are shown. However, it isunderstood that in an oil shale development project, numerous additionalwellbores 14 will most likely be drilled. The wellbores 14 may belocated in relatively close proximity, being from 10 feet to up to 300feet in separation. In some embodiments, a well spacing of 15 to 25 feetis provided. Typically, the wellbores 14 are also completed at shallowdepths, being from 200 to 5,000 feet at total depth. In some embodimentsthe oil shale formation targeted for in situ retorting is at a depthgreater than 200 feet below the surface or alternatively 400 feet belowthe surface. Alternatively, conversion and production of an oil shaleformation occur at depths between 500 and 2,500 feet.

The wellbores 14 will be selected for certain functions and may bedesignated as heat injection wells, water injection wells, oilproduction wells and/or water-soluble mineral solution production wells.In one aspect, the wellbores 14 are dimensioned to serve two, three, orall four of these purposes. Suitable tools and equipment may besequentially run into and removed from the wellbores 14 to serve thevarious purposes.

A fluid processing facility 17 is also shown schematically. The fluidprocessing facility 17 is equipped to receive fluids produced from theorganic-rich rock formation 16 through one or more pipelines or flowlines 18. The fluid processing facility 17 may include equipmentsuitable for receiving and separating oil, gas and water produced fromthe heated formation. The fluid processing facility 17 may furtherinclude equipment for separating out dissolved water-soluble mineralsand/or migratory contaminant species including, for example, dissolvedorganic contaminants, metal contaminants, or ionic contaminants in theproduced water recovered from the organic-rich rock formation 16. Thecontaminants may include, for example, aromatic hydrocarbons such asbenzene, toluene, xylene, and tri-methylbenzene. The contaminants mayalso include polyaromatic hydrocarbons such as anthracene, naphthalene,chrysene and pyrene. Metal contaminants may include species containingarsenic, boron, chromium, mercury, selenium, lead, vanadium, nickel,cobalt, molybdenum, or zinc. Ionic contaminant species may include, forexample, sulfates, chlorides, fluorides, lithium, potassium, aluminum,ammonia, and nitrates.

In order to recover oil, gas, and sodium (or other) water-solubleminerals, a series of steps may be undertaken. FIG. 2 presents a flowchart demonstrating a method of in situ thermal recovery of oil and gasfrom an organic-rich rock formation 100, in one embodiment. It isunderstood that the order of some of the steps from FIG. 2 may bechanged, and that the sequence of steps is merely for illustration.

First, the oil shale (or other organic-rich rock) formation 16 isidentified within the development area 10. This step is shown in box110. Optionally, the oil shale formation may contain nahcolite or othersodium minerals. The targeted development area within the oil shaleformation may be identified by measuring or modeling the depth,thickness and organic richness of the oil shale as well as evaluatingthe position of the organic-rich rock formation relative to other rocktypes, structural features (e.g. faults, anticlines or synclines), orhydrogeological units (i.e. aquifers). This is accomplished by creatingand interpreting maps and/or models of depth, thickness, organicrichness and other data from available tests and sources. This mayinvolve performing geological surface surveys, studying outcrops,performing seismic surveys, and/or drilling boreholes to obtain coresamples from subsurface rock. Rock samples may be analyzed to assesskerogen content and hydrocarbon fluid-generating capability.

The kerogen content of the organic-rich rock formation may beascertained from outcrop or core samples using a variety of data. Suchdata may include organic carbon content, hydrogen index, and modifiedFischer assay analyses. Subsurface permeability may also be assessed viarock samples, outcrops, or studies of ground water flow. Furthermore theconnectivity of the development area to ground water sources may beassessed.

Next, a plurality of wellbores 14 is formed across the targeteddevelopment area 10. This step is shown schematically in box 115. Thepurposes of the wellbores 14 are set forth above and need not berepeated. However, it is noted that for purposes of the wellboreformation step of box 115, only a portion of the wells need be completedinitially. For instance, at the beginning of the project heat injectionwells are needed, while a majority of the hydrocarbon production wellsare not yet needed. Production wells may be brought in once conversionbegins, such as after 4 to 12 months of heating.

It is understood that petroleum engineers will develop a strategy forthe best depth and arrangement for the wellbores 14, depending uponanticipated reservoir characteristics, economic constraints, and workscheduling constraints. In addition, engineering staff will determinewhat wellbores 14 shall be used for initial formation 16 heating. Thisselection step is represented by box 120.

Concerning heat injection wells, there are various methods for applyingheat to the organic-rich rock formation 16. The present methods are notlimited to the heating technique employed unless specifically so statedin the claims. The heating step is represented generally by box 130.Preferably, for in situ processes the heating of a production zone takesplace over a period of months, or even four or more years.

The formation 16 is heated to a temperature sufficient to pyrolyze atleast a portion of the oil shale in order to convert the kerogen tohydrocarbon fluids. The bulk of the target zone of the formation may beheated to between 270° C. to 800° C. Alternatively, the targeted volumeof the organic-rich formation is heated to at least 350° C. to createproduction fluids. The conversion step is represented in FIG. 2 by box135. The resulting liquids and hydrocarbon gases may be refined intoproducts which resemble common commercial petroleum products. Suchliquid products include transportation fuels such as diesel, jet fueland naptha. Generated gases include light alkanes, light alkenes, H₂,CO₂, CO, and NH₃.

Conversion of the oil shale will create permeability in the oil shalesection in rocks that were originally impermeable. Preferably, theheating and conversion processes of boxes 130 and 135, occur over alengthy period of time. In one aspect, the heating period is from threemonths to four or more years. Also as an optional part of box 135, theformation 16 may be heated to a temperature sufficient to convert atleast a portion of nahcolite, if present, to soda ash. Heat applied tomature the oil shale and recover oil and gas will also convert nahcoliteto sodium carbonate (soda ash), a related sodium mineral. The process ofconverting nahcolite (sodium bicarbonate) to soda ash (sodium carbonate)is described herein.

In connection with the heating step 130, the rock formation 16 mayoptionally be fractured to aid heat transfer or later hydrocarbon fluidproduction. The optional fracturing step is shown in box 125. Fracturingmay be accomplished by creating thermal fractures within the formationthrough application of heat. By heating the organic-rich rock andtransforming the kerogen to oil and gas, the permeability increases viathermal fracture formation and subsequent production of a portion of thehydrocarbon fluids generated from the kerogen. Alternatively, a processknown as hydraulic fracturing may be used. Hydraulic fracturing is aprocess known in the art of oil and gas recovery where a fracture fluidis pressurized within the wellbore above the fracture pressure of theformation, thus developing fracture planes within the formation torelieve the pressure generated within the wellbore. Hydraulic fracturesmay be used to create additional permeability in portions of theformation and/or be used to provide a planar source for heating.

As part of the hydrocarbon fluid production process 100, certain wells14 may be designated as oil and gas production wells. This step isdepicted by box 140. Oil and gas production might not be initiated untilit is determined that the kerogen has been sufficiently retorted toallow maximum recovery of oil and gas from the formation 16. In someinstances, dedicated production wells are not drilled until after heatinjection wells (box 130) have been in operation for a period of severalweeks or months. Thus, box 140 may include the formation of additionalwellbores 14. In other instances, selected heater wells are converted toproduction wells.

After certain wellbores 14 have been designated as oil and gasproduction wells, oil and/or gas is produced from the wellbores 14. Theoil and/or gas production process is shown at box 145. At this stage(box 145), any water-soluble minerals, such as nahcolite and convertedsoda ash may remain substantially trapped in the rock formation 16 asfinely disseminated crystals or nodules within the oil shale beds, andare not produced. However, some nahcolite and/or soda ash may bedissolved in the water created during heat conversion (box 135) withinthe formation.

Box 150 presents an optional next step in the oil and gas recoverymethod 100. Here, certain wellbores 14 are designated as water oraqueous fluid injection wells. Aqueous fluids are solutions of waterwith other species. The water may constitute “brine,” and may includedissolved inorganic salts of chloride, sulfates and carbonates of GroupI and II elements of The Periodic Table of Elements. Organic salts canalso be present in the aqueous fluid. The water may alternatively befresh water containing other species. The other species may be presentto alter the pH. Alternatively, the other species may reflect theavailability of brackish water not saturated in the species wished to beleached from the subsurface. Preferably, the water injection wells areselected from some or all of the wellbores used for heat injection orfor oil and/or gas production. However, the scope of the step of box 150may include the drilling of yet additional wellbores 14 for use asdedicated water injection wells. In this respect, it may be desirable tocomplete water injection wells along a periphery of the development area10 in order to create a boundary of high pressure.

Next, optionally water or an aqueous fluid is injected through the waterinjection wells and into the oil shale formation 16. This step is shownat box 155. The water may be in the form of steam or pressurized hotwater. Alternatively the injected water may be cool and becomes heatedas it contacts the previously heated formation. The injection processmay further induce fracturing. This process may create fingered cavernsand brecciated zones in the nahcolite-bearing intervals some distance,for example up to 200 feet out, from the water injection wellbores. Inone aspect, a gas cap, such as nitrogen, may be maintained at the top ofeach “cavern” to prevent vertical growth.

Along with the designation of certain wellbores 14 as water injectionwells, the design engineers may also designate certain wellbores 14 aswater or water-soluble mineral solution production wells. This step isshown in box 160. These wells may be the same as wells used topreviously produce hydrocarbons or inject heat. These recovery wells maybe used to produce an aqueous solution of dissolved water-solubleminerals and other species, including, for example, migratorycontaminant species. For example, the solution may be one primarily ofdissolved soda ash. This step is shown in box 165. Alternatively, singlewellbores may be used to both inject water and then to recover a sodiummineral solution. Thus, box 165 includes the option of using the samewellbores 14 for both water injection and solution production (box 165).

Temporary control of the migration of the migratory contaminant species,especially during the pyrolysis process, can be obtained via placementof the injection and production wells 14 such that fluid flow out of theheated zone is minimized. Typically, this involves placing injectionwells at the periphery of the heated zone so as to cause pressuregradients which prevent flow inside the heated zone from leaving thezone.

FIG. 3 is a cross-sectional view of an illustrative oil shale formationthat is within or connected to ground water aquifers and a formationleaching operation. Four separate oil shale formation zones are depicted(23, 24, 25 and 26) within the oil shale formation. The water aquifersare below the ground surface 27, and are categorized as an upper aquifer20 and a lower aquifer 22. Intermediate the upper and lower aquifers isan aquitard 21. It can be seen that certain zones of the formation areboth aquifers or aquitards and oil shale zones. A plurality of wells(28, 29, 30 and 31) is shown traversing vertically downward through theaquifers. One of the wells is serving as a water injection well 31,while another is serving as a water production well 30. In this way,water is circulated 32 through at least the lower aquifer 22.

FIG. 3 shows diagrammatically the water circulation 32 through an oilshale zone 33 that was heated, that resides within or is connected to anaquifer 22, and from which hydrocarbon fluids were previously recovered.Introduction of water via the water injection well 31 forces water intothe previously heated oil shale zone 33 so that water-soluble mineralsand migratory contaminants species are swept to the water productionwell 30. The water may then be processed in a facility 34 wherein thewater-soluble minerals (e.g. nahcolite or soda ash) and the migratorycontaminants may be substantially removed from the water stream. Wateris then reinjected into the oil shale zone 33 and the formation leachingis repeated. This leaching with water is intended to continue untillevels of migratory contaminant species are at environmentallyacceptable levels within the previously heated oil shale zone 33. Thismay require 1 cycle, 2 cycles, 5 cycles 10 cycles or more cycles offormation leaching, where a single cycle indicates injection andproduction of approximately one pore volume of water.

It is understood that there may be numerous water injection and waterproduction wells in an actual oil shale development. Moreover, thesystem may include monitoring wells (28 and 29) which can be utilizedduring the oil shale heating phase, the shale oil production phase, theleaching phase, or during any combination of these phases to monitor formigratory contaminant species and/or water-soluble minerals.

In some fields, formation hydrocarbons, such as oil shale, may exist inmore than one subsurface formation. In some instances, the organic-richrock formations may be separated by rock layers that arehydrocarbon-free or that otherwise have little or no commercial value.Therefore, it may be desirable for the operator of a field underhydrocarbon development to undertake an analysis as to which of thesubsurface, organic-rich rock formations to target or in which orderthey should be developed.

The organic-rich rock formation may be selected for development based onvarious factors. One such factor is the thickness of the hydrocarboncontaining layer within the formation. Greater pay zone thickness mayindicate a greater potential volumetric production of hydrocarbonfluids. Each of the hydrocarbon containing layers may have a thicknessthat varies depending on, for example, conditions under which theformation hydrocarbon containing layer was formed. Therefore, anorganic-rich rock formation will typically be selected for treatment ifthat formation includes at least one formation hydrocarbon-containinglayer having a thickness sufficient for economical production ofproduced fluids.

An organic-rich rock formation may also be chosen if the thickness ofseveral layers that are closely spaced together is sufficient foreconomical production of produced fluids. For example, an in situconversion process for formation hydrocarbons may include selecting andtreating a layer within an organic-rich rock formation having athickness of greater than about 5 meters, 10 meters, 50 m, or even 100meters. In this manner, heat losses (as a fraction of total injectedheat) to layers formed above and below an organic-rich rock formationmay be less than such heat losses from a thin layer of formationhydrocarbons. A process as described herein, however, may also includeselecting and treating layers that may include layers substantially freeof formation hydrocarbons or thin layers of formation hydrocarbons.

The richness of one or more organic-rich rock formations may also beconsidered. Richness may depend on many factors including the conditionsunder which the formation hydrocarbon containing layer was formed, anamount of formation hydrocarbons in the layer, and/or a composition offormation hydrocarbons in the layer. A thin and rich formationhydrocarbon layer may be able to produce significantly more valuablehydrocarbons than a much thicker, less rich formation hydrocarbon layer.Of course, producing hydrocarbons from a formation that is both thickand rich is desirable.

The kerogen content of an organic-rich rock formation may be ascertainedfrom outcrop or core samples using a variety of data. Such data mayinclude organic carbon content, hydrogen index, and modified Fischerassay analyses. The Fischer Assay is a standard method which involvesheating a sample of a formation hydrocarbon containing layer toapproximately 500° C. in one hour, collecting fluids produced from theheated sample, and quantifying the amount of fluids produced.

Subsurface formation permeability may also be assessed via rock samples,outcrops, or studies of ground water flow. Furthermore the connectivityof the development area to ground water sources may be assessed. Thus,an organic-rich rock formation may be chosen for development based onthe permeability or porosity of the formation matrix even if thethickness of the formation is relatively thin.

Other factors known to petroleum engineers may be taken intoconsideration when selecting a formation for development. Such factorsinclude depth of the perceived pay zone, stratigraphic proximity offresh ground water to kerogen-containing zones, continuity of thickness,and other factors. For instance, the assessed fluid production contentwithin a formation will also effect eventual volumetric production.

As noted above, several different types of wells may be used in thedevelopment of an organic-rich rock formation, including, for example,an oil shale field. For example, the heating of the organic-rich rockformation may be accomplished through the use of heater wells. Theheater wells may include, for example, electrical resistance heatingelements. The production of hydrocarbon fluids from the formation may beaccomplished through the use of wells completed for the production offluids. The injection of an aqueous fluid may be accomplished throughthe use of injection wells. Finally, the production of an aqueoussolution may be accomplished through use of solution production wells.

The different wells listed above may be used for more than one purpose.Stated another way, wells initially completed for one purpose may laterbe used for another purpose, thereby lowering project costs and/ordecreasing the time required to perform certain tasks. For example, oneor more of the production wells may also be used as injection wells forlater injecting water into the organic-rich rock formation.Alternatively, one or more of the production wells may also be used assolution production wells for later producing an aqueous solution fromthe organic-rich rock formation.

In other aspects, production wells (and in some circumstances heaterwells) may initially be used as dewatering wells (e.g., before heatingis begun and/or when heating is initially started). In addition, in somecircumstances dewatering wells can later be used as production wells(and in some circumstances heater wells). As such, the dewatering wellsmay be placed and/or designed so that such wells can be later used asproduction wells and/or heater wells. The heater wells may be placedand/or designed so that such wells can be later used as production wellsand/or dewatering wells. The production wells may be placed and/ordesigned so that such wells can be later used as dewatering wells and/orheater wells. Similarly, injection wells may be wells that initiallywere used for other purposes (e.g., heating, production, dewatering,monitoring, etc.), and injection wells may later be used for otherpurposes. Similarly, monitoring wells may be wells that initially wereused for other purposes (e.g., heating, production, dewatering,injection, etc.). Finally, monitoring wells may later be used for otherpurposes such as water production.

The wellbores for the various wells may be located in relatively closeproximity, being from 10 feet to up to 300 feet in separation.Alternatively, the wellbores may be spaced from 30 to 200 feet or 50 to100 feet. Typically, the wellbores are also completed at shallow depths,being from 200 to 5,000 feet at total depth. Alternatively, thewellbores may be completed at depths from 1,000 to 4,000 feet, or 1,500to 3,500 feet. In some embodiments, the oil shale formation targeted forin situ retorting is at a depth greater than 200 feet below the surface.In alternative embodiments, the oil shale formation targeted for in situretorting is at a depth greater than 500, 1,000, or 1,500 feet below thesurface. In alternative embodiments, the oil shale formation targetedfor in situ retorting is at a depth between 200 and 5,000 feet,alternatively between 1,000 and 4,000 ft, 1,200 and 3,700 feet, or 1,500and 3,500 feet below the surface.

It is desirable to arrange the various wells for an oil shale field in apre-planned pattern. For instance, heater wells. may be arranged in avariety of patterns including, but not limited to triangles, squares,hexagons, and other polygons. The pattern may include a regular polygonto promote uniform heating through at least the portion of the formationin which the heater wells are placed. The pattern may also be a linedrive pattern. A line drive pattern generally includes a first lineararray of heater wells, a second linear array of heater wells, and aproduction well or a linear array of production wells between the firstand second linear array of heater wells. Interspersed among the heaterwells are typically one or more production wells. The injection wellsmay likewise be disposed within a repetitive pattern of units, which maybe similar to or different from that used for the heater wells.

One method to reduce the number of wells is to use a single well as botha heater well and a production well. Reduction of the number of wells byusing single wells for sequential purposes can reduce project costs. Oneor more monitoring wells may be disposed at selected points in thefield. The monitoring wells may be configured with one or more devicesthat measure a temperature, a pressure, and/or a property of a fluid inthe wellbore. In some instances, a heater well may also serve as amonitoring well, or otherwise be instrumented.

Another method for reducing the number of heater wells is to use wellpatterns. Regular patterns of heater wells equidistantly spaced from aproduction well may be used. The patterns may form equilateraltriangular arrays, hexagonal arrays, or other array patterns. The arraysof heater wells may be disposed such that a distance between each heaterwell is less than about 70 feet (21 m). A portion of the formation maybe heated with heater wells disposed substantially parallel to aboundary of the hydrocarbon formation.

In alternative embodiments, the array of heater wells may be disposedsuch that a distance between each heater well may be less than about 100feet, or 50 feet, or 30 feet. Regardless of the arrangement of ordistance between the heater wells, in certain embodiments, a ratio ofheater wells to production wells disposed within a organic-rich rockformation may be greater than about 5, 8, 10, 20, or more.

In one embodiment, individual production wells are surrounded by at mostone layer of heater wells. This may include arrangements such as 5-spot,7-spot, or 9-spot arrays, with alternating rows of production and heaterwells. In another embodiment, two layers of heater wells may surround aproduction well, but with the heater wells staggered so that a clearpathway exists for the majority of flow away from the further heaterwells. Flow and reservoir simulations may be employed to assess thepathways and temperature history of hydrocarbon fluids generated in situas they migrate from their points of origin to production wells.

FIG. 4 provides a plan view of an illustrative heater well arrangementusing more than one layer of heater wells. The heater well arrangementis used in connection with the production of hydrocarbons from a shaleoil development area 400. In FIG. 4, the heater well arrangement employsa first layer of heater wells 410, surrounded by a second layer ofheater wells 420. The heater wells in the first layer 410 are referencedat 431, while the heater wells in the second layer 420 are referenced at432.

A production well 440 is shown central to the well layers 410 and 420.It is noted that the heater wells 432 in the second layer 420 of wellsare offset from the heater wells 431 in the first layer 410 of wells,relative to the production well 440. The purpose is to provide aflowpath for converted hydrocarbons that minimizes travel near a heaterwell in the first layer 410 of heater wells. This, in turn, minimizessecondary cracking of hydrocarbons converted from kerogen ashydrocarbons flow from the second layer of wells 420 to the productionwells 440.

In the illustrative arrangement of FIG. 4, the first layer 410 and thesecond layer 420 each defines a 5-spot pattern. However, it isunderstood that other patterns may be employed, such as 3-spot or 6-spotpatterns. In any instance, a plurality of heater wells 431 comprising afirst layer of heater wells 410 is placed around a production well 440,with a second plurality of heater wells 432 comprising a second layer ofheater wells 420 placed around the first layer 410.

The heater wells in the two layers also may be arranged such that themajority of hydrocarbons generated by heat from each heater well 432 inthe second layer 420 are able to migrate to a production well 440without passing substantially near a heater well 431 in the first layer410. The heater wells 431, 432 in the two layers 410, 420 further may bearranged such that the majority of hydrocarbons generated by heat fromeach heater well 432 in the second layer 420 are able to migrate to theproduction well 440 without passing through a zone of substantiallyincreasing formation temperature.

One method to reduce the number of heater wells is to use well patternsthat are elongated in a particular direction, particularly in thedirection of most efficient thermal conductivity. Heat convection may beaffected by various factors such as bedding planes and stresses withinthe formation. For instance, heat convection may be more efficient inthe direction perpendicular to the least horizontal principal stress onthe formation. In some instanced, heat convection may be more efficientin the direction parallel to the least horizontal principal stress.

In connection with the development of an oil shale field, it may bedesirable that the progression of heat through the subsurface inaccordance with steps 130 and 135 be uniform. However, for variousreasons the heating and maturation of formation hydrocarbons in asubsurface formation may not proceed uniformly despite a regulararrangement of heater and production wells. Heterogeneities in the oilshale properties and formation structure may cause certain local areasto be more or less productive. Moreover, formation fracturing whichoccurs due to the heating and maturation of the oil shale can lead to anuneven distribution of preferred pathways and, thus, increase flow tocertain production wells and reduce flow to others. Uneven fluidmaturation may be an undesirable condition since certain subsurfaceregions may receive more heat energy than necessary where other regionsreceive less than desired. This, in turn, leads to the uneven flow andrecovery of production fluids. Produced oil quality, overall productionrate, and/or ultimate recoveries may be reduced.

To detect uneven flow conditions, production and heater wells may beinstrumented with sensors. Sensors may include equipment to measuretemperature, pressure, flow rates, and/or compositional information.Data from these sensors can be processed via simple rules or input todetailed simulations to reach decisions on how to adjust heater andproduction wells to improve subsurface performance. Production wellperformance may be adjusted by controlling backpressure or throttling onthe well. Heater well performance may also be adjusted by controllingenergy input. Sensor readings may also sometimes imply mechanicalproblems with a well or downhole equipment which requires repair,replacement, or abandonment.

In one embodiment, flow rate, compositional, temperature and/or pressuredata are utilized from two or more wells as inputs to a computeralgorithm to control heating rate and/or production rates. Unmeasuredconditions at or in the neighborhood of the well are then estimated andused to control the well. For example, in situ fracturing behavior andkerogen maturation are estimated based on thermal, flow, andcompositional data from a set of wells. In another example, wellintegrity is evaluated based on pressure data, well temperature data,and estimated in situ stresses. In a related embodiment the number ofsensors is reduced by equipping only a subset of the wells withinstruments, and using the results to interpolate, calculate, orestimate conditions at uninstrumented wells. Certain wells may have onlya limited set of sensors (e.g., wellhead temperature and pressure only)where others have a much larger set of sensors (e.g., wellheadtemperature and pressure, bottomhole temperature and pressure,production composition, flow rate, electrical signature, casing strain,etc.).

As noted above, there are various methods for applying heat to anorganic-rich rock formation. For example, one method may includeelectrical resistance heaters disposed in a wellbore or outside of awellbore. One such method involves the use of electrical resistiveheating elements in a cased or uncased wellbore. Electrical resistanceheating involves directly passing electricity through a conductivematerial such that resistive losses cause it to heat the conductivematerial. Other heating methods include the use of downhole combustors,in situ combustion, radio-frequency (RF) electrical energy, or microwaveenergy. Still others include injecting a hot fluid into the oil shaleformation to directly heat it. The hot fluid may or may not becirculated. One method may include generating heat by burning a fuelexternal to or within a subsurface formation. For example, heat may besupplied by surface burners or downhole burners or by circulating hotfluids (such as methane gas or naphtha) into the formation through, forexample, wellbores via, for example, natural or artificial fractures.Some burners may be configured to perform flameless combustion.Alternatively, some methods may include combusting fuel within theformation such as via a natural distributed combustor, which generallyrefers to a heater that uses an oxidant to oxidize at least a portion ofthe carbon in the formation to generate heat, and wherein the oxidationtakes place in a vicinity proximate to a wellbore. The present methodsare not limited to the heating technique employed unless so stated inthe claims.

One method for formation heating involves the use of electricalresistors in which an electrical current is passed through a resistivematerial which dissipates the electrical energy as heat. This method isdistinguished from dielectric heating in which a high-frequencyoscillating electric current induces electrical currents in nearbymaterials and causes them to heat. The electric heater may include aninsulated conductor, an elongated member disposed in the opening, and/ora conductor disposed in a conduit. An early patent disclosing the use ofelectrical resistance heaters to produce oil shale in situ is U.S. Pat.No. 1,666,488. The '488 patent issued to Crawshaw in 1928. Since 1928,various designs for downhole electrical heaters have been proposed.Illustrative designs are presented in U.S. Pat. Nos. 1,701,884,3,376,403, 4,626,665, 4,704,514, and 6,023,554).

A review of application of electrical heating methods for heavy oilreservoirs is given by R. Sierra and S. M. Farouq Ali, “PromisingProgress in Field Application of Reservoir Electrical Heating Methods”,Society of Petroleum Engineers Paper 69709, 2001. The entire disclosureof this reference is hereby incorporated by reference.

Certain previous designs for in situ electrical resistance heatersutilized solid, continuous heating elements (e.g., metal wires orstrips). However, such elements may lack the necessary robustness forlong-term, high temperature applications such as oil shale maturation.As the formation heats and the oil shale matures, significant expansionof the rock occurs. This leads to high stresses on wells intersectingthe formation. These stresses can lead to bending and stretching of thewellbore pipe and internal components. Cementing (e.g., U.S. Pat. No.4,886,118) or packing (e.g., U.S. Pat. No. 2,732,195) a heating elementin place may provide some protection against stresses, but some stressesmay still be transmitted to the heating element.

As an alternative, international patent publication WO 2005/010320teaches the use of electrically conductive fractures to heat the oilshale. A heating element is constructed by forming wellbores and thenhydraulically fracturing the oil shale formation around the wellbores.The fractures are filled with an electrically conductive material whichforms the heating element. Calcined petroleum coke is an exemplarysuitable conductant material. Preferably, the fractures are created in avertical orientation along longitudinal, horizontal planes formed byhorizontal wellbores. Electricity may be conducted through theconductive fractures from the heel to the toe of each well. Theelectrical circuit may be completed by an additional horizontal wellthat intersects one or more of the vertical fractures near the toe tosupply the opposite electrical polarity. The WO 2005/010320 processcreates an “in situ toaster” that artificially matures oil shale throughthe application of electric heat. Thermal conduction heats the oil shaleto conversion temperatures in excess of 300° C. causing artificialmaturation.

International patent publication WO 2005/045192 teaches an alternativeheating means that employs the circulation of a heated fluid within anoil shale formation. In the process of WO 2005/045192 supercriticalheated naphtha may be circulated through fractures in the formation.This means that the oil shale is heated by circulating a dense, hothydrocarbon vapor through sets of closely-spaced hydraulic fractures. Inone aspect, the fractures are horizontally formed and conventionallypropped. Fracture temperatures of 320°-400° C. are maintained for up tofive to ten years. Vaporized naptha may be the preferred heating mediumdue to its high volumetric heat capacity, ready availability andrelatively low degradation rate at the heating temperature. In the WO2005/045192 process, as the kerogen matures, fluid pressure will drivethe generated oil to the heated fractures, where it will be producedwith the cycling hydrocarbon vapor.

The purpose for heating the organic-rich rock formation is to pyrolyzeat least a portion of the solid formation hydrocarbons to createhydrocarbon fluids. The solid formation hydrocarbons may be pyrolyzed insitu by raising the organic-rich rock formation, (or zones within theformation), to a pyrolyzation temperature. In certain embodiments, thetemperature of the formation may be slowly raised through the pyrolysistemperature range. For example, an in situ conversion process mayinclude heating at least a portion of the organic-rich rock formation toraise the average temperature of the zone above about 270° C. at a rateless than a selected amount (e.g., about 10° C., 5° C.; 3° C., 1° C.,0.5° C., or 0.1° C.) per day. In a further embodiment, the portion maybe heated such that an average temperature of the selected zone may beless than about 375° C. or, in some embodiments, less than about 40° C.The formation may be heated such that a temperature within the formationreaches (at least) an initial pyrolyzation temperature (e.g., atemperature at the lower end of the temperature range where pyrolyzationbegins to occur.

The pyrolysis temperature range may vary depending on the types offormation hydrocarbons within the formation, the heating methodology,and the distribution of heating sources. For example, a pyrolysistemperature range may include temperatures between about 270° C. andabout 900° C. Alternatively, the bulk of the target zone of theformation may be heated to between 300° to 600° C. In an alternativeembodiment, a pyrolysis temperature range may include temperaturesbetween about 270° C. to about 500° C.

Preferably, for in situ processes the heating of a production zone takesplace over a period of months, or even four or more years.Alternatively, the formation may be heated for one to fifteen years,alternatively, 3 to 10 years, 1.5 to 7 years, or 2 to 5 years. The bulkof the target zone of the formation may be heated to between 270° to800° C. Preferably, the bulk of the target zone of the formation isheated to between 300° to 600° C. Alternatively, the bulk of the targetzone is ultimately heated to a temperature below 400° C. (752° F.).

In certain embodiments of the methods of the present invention, downholeburners may be used to heat a targeted oil shale zone. Downhole burnersof various design have been discussed in the patent literature for usein oil shale and other largely solid hydrocarbon deposits. Examplesinclude U.S. Pat. Nos. 2,887,160; 2,847,071; 2,895,555; 3,109,482;3,225,829; 3,241,615; 3,254,721; 3,127,936; 3,095,031; 5,255,742; and5,899,269. Downhole burners operate through the transport of acombustible fuel (typically natural gas) and an oxidizer (typically air)to a subsurface position in a wellbore. The fuel and oxidizer reactdownhole to generate heat. The combustion gases are removed (typicallyby transport to the surface, but possibly via injection into theformation). Oftentimes, downhole burners utilize pipe-in-pipearrangements to transport fuel and oxidizer downhole, and then to removethe flue gas back up to the surface. Some downhole burners generate aflame, while others may not.

The use of downhole burners is an alternative to another form ofdownhole heat generation called steam generation. In downhole steamgeneration, a combustor in the well is used to boil water placed in thewellbore for injection into the formation. Applications of the downholeheat technology have been described in F. M. Smith, “A Down-holeburner—Versatile tool for well heating,” 25^(th) Technical Conference onPetroleum Production, Pennsylvania State University, pp 275-285 (Oct.19-21, 1966); H. Brandt, W. G. Poynter, and J. D. Hummell, “StimulatingHeavy Oil Reservoirs with Downhole Air-Gas Burners,” World Oil, pp.91-95 (September 1965); and C. I. DePriester and A. J. Pantaleo, “WellStimulation by Downhole Gas-Air Burner,” Journal of PetroleumTechnology, pp. 1297-1302 (December 1963).

Downhole burners have advantages over electrical heating methods due tothe reduced infrastructure cost. In this respect, there is no need foran expensive electrical power plant and distribution system. Moreover,there is increased thermal efficiency because the energy lossesinherently experienced during electrical power generation are avoided.

Few applications of downhole burners exist due to various design issues.Downhole burner design issues include temperature control and metallurgylimitations. In this respect, the flame temperature can overheat thetubular and burner hardware and cause them to fail via melting, thermalstresses, severe loss of tensile strength, or creep. Certain stainlesssteels, typically with high chromium content, can tolerate temperaturesup to ˜700° C. for extended periods. (See for example H. E. Boyer and T.L. Gall (eds.), Metals Handbook, “Chapter 16: Heat-Resistant Materials”,American Society for Metals, (1985.) The existence of flames can causehot spots within the burner and in the formation surrounding the burner.This is due to radiant heat transfer from the luminous portion of theflame. However, a typical gas flame can produce temperatures up to about1,650° C. Materials of construction for the burners must be sufficientto withstand the temperatures of these hot spots. The heaters aretherefore more expensive than a comparable heater without flames.

For downhole burner applications, heat transfer can occur in one ofseveral ways. These include conduction, convection, and radiativemethods. Radiative heat transfer can be particularly strong for an openflame. Additionally, the flue gases can be corrosive due to the CO₂ andwater content. Use of refractory metals or ceramics can help solve theseproblems, but typically at a higher cost. Ceramic materials withacceptable strength at temperatures in excess of 900° C. are generallyhigh alumina content ceramics. Other ceramics that may be useful includechrome oxide, zirconia oxide, and magnesium oxide based ceramics.Additionally, depending on the nature of the downhole combustion NO_(x)generation may be significant.

Heat transfer in a pipe-in-pipe arrangement for a downhole burner canalso lead to difficulties. The down going fuel and air will heatexchange with the up going hot flue gases. In a well there is minimalroom for a high degree of insulation and hence significant heat transferis typically expected. This cross heat exchange can lead to higher flametemperatures as the fuel and air become preheated. Additionally, thecross heat exchange can limit the transport of heat downstream of theburner since the hot flue gases may rapidly lose heat energy to therising cooler flue gases.

In the production of oil and gas resources, it may be desirable to usethe produced hydrocarbons as a source of power for ongoing operations.This may be applied to the development of oil and gas resources from oilshale. In this respect, when electrically resistive heaters are used inconnection with in situ shale oil recovery, large amounts of power arerequired.

Electrical power may be obtained from turbines that turn generators. Itmay be economically advantageous to power the gas turbines by utilizingproduced gas from the field. However, such produced gas must becarefully controlled so not to damage the turbine, cause the turbine tomisfire, or generate excessive pollutants (e.g., NO_(x)).

One source of problems for gas turbines is the presence of contaminantswithin the fuel. Contaminants include solids, water, heavy componentspresent as liquids, and hydrogen sulfide. Additionally, the combustionbehavior of the fuel is important. Combustion parameters to considerinclude heating value, specific gravity, adiabatic flame temperature,flammability limits, autoignition temperature, autoignition delay time,and flame velocity. Wobbe Index (WI) is often used as a key measure offuel quality. WI is equal to the ratio of the lower heating value to thesquare root of the gas specific gravity. Control of the fuel's WobbeIndex to a target value and range of, for example, ±10% or ±20% canallow simplified turbine design and increased optimization ofperformance.

Fuel quality control may be useful for shale oil developments where theproduced gas composition may change over the life of the field and wherethe gas typically has significant amounts of CO₂, CO, and H₂ in additionto light hydrocarbons. Commercial scale oil shale retorting is expectedto produce a gas composition that changes with time.

Inert gases in the turbine fuel can increase power generation byincreasing mass flow while maintaining a flame temperature in adesirable range. Moreover inert gases can lower flame temperature andthus reduce NO_(x) pollutant generation. Gas generated from oil shalematuration may have significant CO₂ content. Therefore, in certainembodiments of the production processes, the CO₂ content of the fuel gasis adjusted via separation or addition in the surface facilities tooptimize turbine performance.

Achieving a certain hydrogen content for low-BTU fuels may also bedesirable to achieve appropriate burn properties. In certain embodimentsof the processes herein, the H₂ content of the fuel gas is adjusted viaseparation or addition in the surface facilities to optimize turbineperformance. Adjustment of H₂ content in non-shale oil surfacefacilities utilizing low BTU fuels has been discussed in the patentliterature (e.g., U.S. Pat. Nos. 6,684,644 and 6,858,049, the entiredisclosures of which are hereby incorporated by reference).

The process of heating formation hydrocarbons within an organic-richrock formation, for example, by pyrolysis, may generate fluids. Theheat-generated fluids may include water which is vaporized within theformation. In addition, the action of heating kerogen produces pyrolysisfluids which tend to expand upon heating. The produced pyrolysis fluidsmay include not only water, but also, for example, hydrocarbons, oxidesof carbon, ammonia, molecular nitrogen, and molecular hydrogen.Therefore, as temperatures within a heated portion of the formationincrease, a pressure within the heated portion may also increase as aresult of increased fluid generation, molecular expansion, andvaporization of water. Thus, some corollary exists between subsurfacepressure in an oil shale formation and the fluid pressure generatedduring pyrolysis. This, in turn, indicates that formation pressure maybe monitored to detect the progress of a kerogen conversion process.

The pressure within a heated portion of an organic-rich rock formationdepends on other reservoir characteristics. These may include, forexample, formation depth, distance from a heater well, a richness of theformation hydrocarbons within the organic-rich rock formation, thedegree of heating, and/or a distance from a producer well.

It may be desirable for the developer of an oil shale field to monitorformation pressure during development. Pressure within a formation maybe determined at a number of different locations. Such locations mayinclude, but may not be limited to, at a wellhead and at varying depthswithin a wellbore. In some embodiments, pressure may be measured at aproducer well. In an alternate embodiment, pressure may be measured at aheater well. In still another embodiment, pressure may be measureddownhole of a dedicated monitoring well.

The process of heating an organic-rich rock formation to a pyrolysistemperature range not only will increase formation pressure, but willalso increase formation permeability. The pyrolysis temperature rangeshould be reached before substantial permeability has been generatedwithin the organic-rich rock formation. An initial lack of permeabilitymay prevent the transport of generated fluids from a pyrolysis zonewithin the formation. In this manner, as heat is initially transferredfrom a heater well to an organic-rich rock formation, a fluid pressurewithin the organic-rich rock formation may increase proximate to thatheater well. Such an increase in fluid pressure may be caused by, forexample, the generation of fluids during pyrolysis of at least someformation hydrocarbons in the formation.

Alternatively, pressure generated by expansion of pyrolysis fluids orother fluids generated in the formation may be allowed to increase. Thisassumes that an open path to a production well or other pressure sinkdoes not yet exist in the formation. In one aspect, a fluid pressure maybe allowed to increase to or above a lithostatic stress. In thisinstance, fractures in the hydrocarbon containing formation may formwhen the fluid pressure equals or exceeds the lithostatic stress. Forexample, fractures may form from a heater well to a production well. Thegeneration of fractures within the heated portion may reduce pressurewithin the portion due to the production of produced fluids through aproduction well.

Once pyrolysis has begun within an organic-rich rock formation, fluidpressure may vary depending upon various factors. These include, forexample, thermal expansion of hydrocarbons, generation of pyrolysisfluids, rate of conversion, and withdrawal of generated fluids from theformation. For example, as fluids are generated within the formation,fluid pressure within the pores may increase. Removal of generatedfluids from the formation may then decrease the fluid pressure withinthe near wellbore region of the formation.

In certain embodiments, a mass of at least a portion of an organic-richrock formation may be reduced due, for example, to pyrolysis offormation hydrocarbons and the production of hydrocarbon fluids from theformation. As such, the permeability and porosity of at least a portionof the formation may increase. Any in situ method that effectivelyproduces oil and gas from oil shale will create permeability in what wasoriginally a very low permeability rock. The extent to which this willoccur is illustrated by the large amount of expansion that must beaccommodated if fluids generated from kerogen are unable to flow. Theconcept is illustrated in FIG. 5.

FIG. 5 provides a bar chart comparing one ton of Green River oil shalebefore 50 and after 51 a simulated in situ, retorting process. Thesimulated process was carried out at 2,400 psi and 750° F. on oil shalehaving a total organic carbon content of 22 wt. % and a Fisher assay of42 gallons/ton. Before the conversion, a total of 15.3 ft³ of rockmatrix 52 existed. This matrix comprised 7.2 ft³ of mineral 53, i.e.,dolomite, limestone, etc., and 8.1 ft³ of kerogen 54 imbedded within theshale. As a result of the conversion the material expanded to 26.1 ft³55. This represented 7.2 ft³ of mineral 56 (the same number as beforethe conversion), 6.6 ft³ of hydrocarbon liquid 57, 9.4 ft³ ofhydrocarbon vapor 58, and 2.9 ft³ of coke 59. It can be seen thatsubstantial volume expansion occurred during the conversion process.This, in turn, increases permeability of the rock structure.

In an embodiment, heating a portion of an organic-rich rock formation insitu to a pyrolysis temperature may increase permeability of the heatedportion. For example, permeability may increase due to formation ofthermal fractures within the heated portion caused by application ofheat. As the temperature of the heated portion increases, water may beremoved due to vaporization. The vaporized water may escape and/or beremoved from the formation. In addition, permeability of the heatedportion may also increase as a result of production of hydrocarbonfluids from pyrolysis of at least some of the formation hydrocarbonswithin the heated portion on a macroscopic scale.

Certain systems and methods described herein may be used to treatformation hydrocarbons in at least a portion of a relatively lowpermeability formation (e.g., in “tight” formations that containformation hydrocarbons). Such formation hydrocarbons may be heated topyrolyze at least some of the formation hydrocarbons in a selected zoneof the formation. Heating may also increase the permeability of at leasta portion of the selected zone. Hydrocarbon fluids generated frompyrolysis may be produced from the formation, thereby further increasingthe formation permeability.

Permeability of a selected zone within the heated portion of theorganic-rich rock formation may also rapidly increase while the selectedzone is heated by conduction. For example, permeability of animpermeable organic-rich rock formation may be less than about 0.1millidarcy before heating. In some embodiments, pyrolyzing at least aportion of organic-rich rock formation may increase permeability withina selected zone of the portion to greater than about 10 millidarcies,100 millidarcies, 1 Darcy, 10 Darcies, 20 Darcies, or 50 Darcies.Therefore, a permeability of a selected zone of the portion may increaseby a factor of more than about 10, 100, 1,000, 10,000, or 100,000. Inone embodiment, the organic-rich rock formation has an initial totalpermeability less than 1 millidarcy, alternatively less than 0.1 or 0.01millidarcies, before heating the organic-rich rock formation. In oneembodiment, the organic-rich rock formation has a post heating totalpermeability of greater than 1 millidarcy, alternatively, greater than10, 50 or 100 millidarcies, after heating the organic-rich rockformation.

In connection with the heating step 130, the organic-rich rock formationmay optionally be fractured to aid heat transfer or hydrocarbon fluidproduction. In one instance, fracturing may be accomplished naturally bycreating thermal fractures within the formation through application ofheat. Thermal fracture formation is caused by thermal expansion of therock and fluids and by chemical expansion of kerogen transforming intooil and gas. Thermal fracturing can occur both in the immediate regionundergoing heating, and in cooler neighboring regions. The thermalfracturing in the neighboring regions is due to propagation of fracturesand tension stresses developed due to the expansion in the hotter zones.Thus, by both heating the organic-rich rock and transforming the kerogento oil and gas, the permeability is increased not only from fluidformation and vaporization, but also via thermal fracture formation. Theincreased permeability aids fluid flow within the formation andproduction of the hydrocarbon fluids generated from the kerogen.

In addition, a process known as hydraulic fracturing may be used.Hydraulic fracturing is a process known in the art of oil and gasrecovery where a fracture fluid is pressurized within the wellbore abovethe fracture pressure of the formation, thus developing fracture planeswithin the formation to relieve the pressure generated within thewellbore. Hydraulic fractures may be used to create additionalpermeability and/or be used to provide an extended geometry for a heaterwell. The WO 2005/010320 patent publication incorporated above describesone such method.

In connection with the production of hydrocarbons from a rock matrix,particularly those of shallow depth, a concern may exist with respect toearth subsidence. This is particularly true in the in situ heating oforganic-rich rock where a portion of the matrix itself is thermallyconverted and removed. Initially, the formation may contain formationhydrocarbons in solid form, such as, for example, kerogen. The formationmay also initially contain water-soluble minerals. Initially, theformation may also be substantially impermeable to fluid flow.

The in situ heating of the matrix pyrolyzes at least a portion of theformation hydrocarbons to create hydrocarbon fluids. This, in turn,creates permeability within a matured (pyrolyzed) organic-rich rock zonein the organic-rich rock formation. The combination of pyrolyzation andincreased permeability permits hydrocarbon fluids to be produced fromthe formation. At the same time, the loss of supporting matrix materialalso creates the potential for subsidence relative to the earth surface.

In some instances, subsidence is sought to be minimized in order toavoid environmental or hydrogeological impact. In this respect, changingthe contour and relief of the earth surface, even by a few inches, canchange runoff patterns, affect vegetation patterns, and impactwatersheds. In addition, subsidence has the potential of damagingproduction or heater wells formed in a production area. Such subsidencecan create damaging hoop and compressional stresses on wellbore casings,cement jobs, and equipment downhole.

In order to avoid or minimize subsidence, it is proposed to leaveselected portions of the formation hydrocarbons substantiallyunpyrolyzed. This serves to preserve one or more unmatured, organic-richrock zones. In some embodiments, the unmatured organic-rich rock zonesmay be shaped as substantially vertical pillars extending through asubstantial portion of the thickness of the organic-rich rock formation.

The heating rate and distribution of heat within the formation may bedesigned and implemented to leave sufficient unmatured pillars toprevent subsidence. In one aspect, heat injection wellbores are formedin a pattern such that untreated pillars of oil shale are lefttherebetween to support the overburden and prevent subsidence.

It is preferred that thermal recovery of oil and gas be conducted beforeany solution mining of nahcolite or other water-soluble minerals presentin the formation. Solution mining can generate large voids in a rockformation and collapse breccias in an oil shale development area. Thesevoids and brecciated zones may pose problems for in situ and miningrecovery of oil shale, further increasing the utility of supportingpillars.

In some embodiments, compositions and properties of the hydrocarbonfluids produced by an in situ conversion process may vary depending on,for example, conditions within an organic-rich rock formation.Controlling heat and/or heating rates of a selected section in anorganic-rich rock formation may increase or decrease production ofselected produced fluids.

In one embodiment, operating conditions may be determined by measuringat least one property of the organic-rich rock formation. The measuredproperties may be input into a computer executable program. At least oneproperty of the produced fluids selected to be produced from theformation may also be input into the computer executable program. Theprogram may be operable to determine a set of operating conditions fromat least the one or more measured properties. The program may also beconfigured to determine the set of operating conditions from at leastone property of the selected produced fluids. In this manner, thedetermined set of operating conditions may be configured to increaseproduction of selected produced fluids from the formation.

Certain heater well embodiments may include an operating system that iscoupled to any of the heater wells such as by insulated conductors orother types of wiring. The operating system may be configured tointerface with the heater well. The operating system may receive asignal (e.g., an electromagnetic signal) from a heater that isrepresentative of a temperature distribution of the heater well.Additionally, the operating system may be further configured to controlthe heater well, either locally or remotely. For example, the operatingsystem may alter a temperature of the heater well by altering aparameter of equipment coupled to the heater well. Therefore, theoperating system may monitor, alter, and/or control the heating of atleast a portion of the formation.

In some embodiments, a heater well may be turned down and/or off afteran average temperature in a formation may have reached a selectedtemperature. Turning down and/or off the heater well may reduce inputenergy costs, substantially inhibit overheating of the formation, andallow heat to substantially transfer into colder regions of theformation.

Temperature (and average temperatures) within a heated organic-rich rockformation may vary, depending on, for example, proximity to a heaterwell, thermal conductivity and thermal diffusivity of the formation,type of reaction occurring, type of formation hydrocarbon, and thepresence of water within the organic-rich rock formation. At points inthe field where monitoring wells are established, temperaturemeasurements may be taken directly in the wellbore. Further, at heaterwells the temperature of the immediately surrounding formation is fairlywell understood. However, it is desirable to interpolate temperatures topoints in the formation intermediate temperature sensors and heaterwells.

In accordance with one aspect of the production processes of the presentinventions, a temperature distribution within the organic-rich rockformation may be computed using a numerical simulation model. Thenumerical simulation model may calculate a subsurface temperaturedistribution through interpolation of known data points and assumptionsof formation conductivity. In addition, the numerical simulation modelmay be used to determine other properties of the formation under theassessed temperature distribution. For example, the various propertiesof the formation may include, but are not limited to, permeability ofthe formation.

The numerical simulation model may also include assessing variousproperties of a fluid formed within an organic-rich rock formation underthe assessed temperature distribution. For example, the variousproperties of a formed fluid may include, but are not limited to, acumulative volume of a fluid formed in the formation, fluid viscosity,fluid density, and a composition of the fluid formed in the formation.Such a simulation may be used to assess the performance of acommercial-scale operation or small-scale field experiment. For example,a performance of a commercial-scale development may be assessed basedon, but not limited to, a total volume of product that may be producedfrom a research-scale operation.

Some embodiments include producing at least a portion of the hydrocarbonfluids from the organic-rich rock formation. The hydrocarbon fluids maybe produced through production wells. Production wells may be cased oruncased wells and drilled and completed through methods known in theart.

Some embodiments further include producing a production fluid from theorganic-rich rock formation where the production fluid contains thehydrocarbon fluids and an aqueous fluid. The aqueous fluid may containwater-soluble minerals and/or migratory contaminant species. In suchcase, the production fluid may be separated into a hydrocarbon streamand an aqueous stream at a surface facility. Thereafter thewater-soluble minerals and/or migratory contaminant species may berecovered from the aqueous stream. This embodiment may be combined withany of the other aspects of the invention discussed herein.

The produced hydrocarbon fluids may include a pyrolysis oil component(or condensable component) and a pyrolysis gas component (ornon-condensable component). Condensable hydrocarbons produced from theformation will typically include paraffins, cycloalkanes,mono-aromatics, and di-aromatics as components. Such condensablehydrocarbons may also include other components such as tri-aromatics andother hydrocarbon species.

In certain embodiments, a majority of the hydrocarbons in the producedfluid may have a carbon number of less than approximately 25.Alternatively, less than about 15 weight % of the hydrocarbons in thefluid may have a carbon number greater than approximately 25. Thenon-condensable hydrocarbons may include, but are not limited to,hydrocarbons having carbon numbers less than 5.

In certain embodiments, the API gravity of the condensable hydrocarbonsin the produced fluid may be approximately 20 or above (e.g., 25, 30,40, 50, etc.). In certain embodiments, the hydrogen to carbon atomicratio in produced fluid may be at least approximately 1.7 (e.g., 1.8,1.9, etc.).

Some production procedures include in situ heating of an organic-richrock formation that contains both formation hydrocarbons and formationwater-soluble minerals prior to substantial removal of the formationwater-soluble minerals from the organic-rich rock formation. In someembodiments of the invention there is no need to partially,substantially or completely remove the water-soluble minerals prior toin situ heating. For example, in an oil shale formation that containsnaturally occurring nahcolite, the oil shale may be heated prior tosubstantial removal of the nahcolite by solution mining. Substantialremoval of a water-soluble mineral may represent the degree of removalof a water-soluble mineral that occurs from any commercial solutionmining operation as known in the art. Substantial removal of awater-soluble mineral may be approximated as removal of greater than 5weight percent of the total amount of a particular water-soluble mineralpresent in the zone targeted for hydrocarbon fluid production in theorganic-rich rock formation. In alternative embodiments, in situ heatingof the organic-rich rock formation to pyrolyze formation hydrocarbonsmay be commenced prior to removal of greater than 3 weight percent,alternatively 7 weight percent, 10 weight percent or 13 weight percentof the formation water-soluble minerals from the organic-rich rockformation.

The impact of heating oil shale to produce oil and gas prior toproducing nahcolite is to convert the nahcolite to a more recoverableform (soda ash), and provide permeability facilitating its subsequentrecovery. Water-soluble mineral recovery may take place as soon as theretorted oil is produced, or it may be left for a period of years forlater recovery. If desired, the soda ash can be readily converted backto nahcolite on the surface. The ease with which this conversion can beaccomplished makes the two minerals effectively interchangeable.

In some production processes, heating the organic-rich rock formationincludes generating soda ash by decomposition of nahcolite. The methodmay include processing an aqueous solution containing water-solubleminerals in a surface facility to remove a portion of the water-solubleminerals. The processing step may include removing the water-solubleminerals by precipitation caused by altering the temperature of theaqueous solution.

The water-soluble minerals may include sodium. The water-solubleminerals may also include nahcolite (sodium bicarbonate), soda ash(sodium carbonate), dawsonite (NaAl(CO₃)(OH)₂), or combinations thereof.The surface processing may further include converting the soda ash backto sodium bicarbonate (nahcolite) in the surface facility by reactionwith CO₂. After partial or complete removal of the water-solubleminerals, the aqueous solution may be reinjected into a subsurfaceformation where it may be sequestered. The subsurface formation may bethe same as or different from the original organic-rich rock formation.

In some production processes, heating of the organic-rich rock formationboth pyrolyzes at least a portion of the formation hydrocarbons tocreate hydrocarbon fluids and makes available migratory contaminantspecies previously bound in the organic-rich rock formation. Themigratory contaminant species may be formed through pyrolysis of theformation hydrocarbons, may be liberated from the formation itself uponheating, or may be made accessible through the creation of increasedpermeability upon heating of the formation. The migratory contaminantspecies may be soluble in water or other aqueous fluids present in orinjected into the organic-rich rock formation.

Producing hydrocarbons from pyrolyzed oil shale will generally leavebehind some migratory contaminant species which are at least partiallywater-soluble. Depending on the hydrological connectivity of thepyrolyzed shale oil to shallower zones, these components may eventuallymigrate into ground water in concentrations which are environmentallyunacceptable. The types of potential migratory contaminant speciesdepend on the nature of the oil shale pyrolysis and the composition ofthe oil shale being converted. If the pyrolysis is performed in theabsence of oxygen or air, the contaminant species may include aromatichydrocarbons (e.g. benzene, toluene, ethylbenzene, xylenes),polyaromatic hydrocarbons (e.g. anthracene, pyrene, naphthalene,chrysene), metal contaminants (e.g. As, Co, Pb, Mo, Ni, and Zn), andother species such as sulfates, ammonia, Al, K, Mg, chlorides, flouridesand phenols. If oxygen or air is employed, contaminant species may alsoinclude ketones, alcohols, and cyanides. Further, the specific migratorycontaminant species present may include any subset or combination of theabove-described species.

It may be desirable for a field developer to assess the connectivity ofthe organic-rich rock formation to aquifers. This may be done todetermine if, or to what extent, in situ pyrolysis of formationhydrocarbons in the organic-rich rock formation may create migratoryspecies with the propensity to migrate into an aquifer. If theorganic-rich rock formation is hydrologically connected to an aquifer,precautions may be taken to reduce or prevent species generated orliberated during pyrolysis from entering the aquifer. Alternatively, theorganic-rich rock formation may be flushed with water or an aqueousfluid after pyrolysis as described herein to remove water-solubleminerals and/or migratory contaminant species. In other embodiments, theorganic-rich rock formation may be substantially hydrologicallyunconnected to any source of ground water. In such a case, flushing theorganic-rich rock formation may not be desirable for removal ofmigratory contaminant species but may nevertheless be desirable forrecovery of water-soluble minerals.

Following production of hydrocarbons from an organic-rich formation,some migratory contaminant species may remain in the rock formation. Insuch case, it may be desirable to inject an aqueous fluid into theorganic-rich rock formation and have the injected aqueous fluid dissolveat least a portion of the water-soluble minerals and/or the migratorycontaminant species to form an aqueous solution. The aqueous solutionmay then be produced from the organic-rich rock formation through, forexample, solution production wells. The aqueous fluid may be adjusted toincrease the solubility of the migratory contaminant species and/or thewater-soluble minerals. The adjustment may include the addition of anacid or base to adjust the pH of the solution. The resulting aqueoussolution may then be produced from the organic-rich rock formation tothe surface for processing.

After initial aqueous fluid production, it may further be desirable toflush the matured organic-rich rock zone and the unmatured organic-richrock zone with an aqueous fluid. The aqueous fluid may be used tofurther dissolve water-soluble minerals and migratory contaminantspecies. The flushing may optionally be completed after a substantialportion of the hydrocarbon fluids have been produced from the maturedorganic-rich rock zone. In some embodiments, the flushing step may bedelayed after the hydrocarbon fluid production step. The flushing may bedelayed to allow heat generated from the heating step to migrate deeperinto surrounding unmatured organic-rich rock zones to convert nahcolitewithin the surrounding unmatured organic-rich rock zones to soda ash.Alternatively, the flushing may be delayed to allow heat generated fromthe heating step to generate permeability within the surroundingunmatured organic-rich rock zones. Further, the flushing may be delayedbased on current and/or forecast market prices of sodium bicarbonate,soda ash, or both as further discussed herein. This method may becombined with any of the other aspects of the invention as discussedherein

Upon flushing of an aqueous solution, it may be desirable to process theaqueous solution in a surface facility to remove at least some of themigratory contaminant species. The migratory contaminant species may beremoved through use of, for example, an adsorbent material, reverseosmosis, chemical oxidation, bio-oxidation, and/or ion exchange.Examples of these processes are individually known in the art. Exemplaryadsorbent materials may include activated carbon, clay, or fuller'searth.

In certain areas with oil shale resources, additional oil shaleresources or other hydrocarbon resources may exist at lower depths.Other hydrocarbon resources may include natural gas in low permeabilityformations (so-called “tight gas”) or natural gas trapped in andadsorbed on coal (so called “coalbed methane”). In some embodiments withmultiple shale oil resources it may be advantageous to develop deeperzones first and then sequentially shallower zones. In this way, wellswill need not cross hot zones or zones of weakened rock. In otherembodiments in may be advantageous to develop deeper zones by drillingwells through regions being utilized as pillars for shale oildevelopment at a shallower depth.

Simultaneous development of shale oil resources and natural gasresources in the same area can synergistically utilize certain facilityand logistic operations. For example, gas treating may be performed at asingle plant. Likewise personnel may be shared among the developments.

FIG. 15 illustrates a schematic diagram of an embodiment of surfacefacilities 1570 that may be configured to treat a produced fluid. Theproduced fluid 1585 may be produced from the subsurface formation 1584though a production well 1571 as described herein. The produced fluidmay include any of the produced fluids produced by any of the methods asdescribed herein. The subsurface formation 1584 may be any subsurfaceformation, including, for example, an organic-rich rock formationcontaining any of oil shale, coal, or tar sands for example. Aproduction scheme may involve quenching 1572 produced fluids to atemperature below 300° F., 200° F., or even 100° F., separating outcondensable components (i.e., oil 1574 and water 1575) in an oilseparator 1573, treating the noncondensable components 1576 (i.e. gas)in a gas treating unit 1577 to remove water 1578 and sulfur species1579, removing the heavier components from the gas (e.g., propane andbutanes) in a gas plant 1581 to form liquid petroleum gas (LPG) 1580 forsale, and generating electrical power 1582 in a power plant 1588 fromthe remaining gas 1583. The electrical power 1582 may be used as anenergy source for heating the subsurface formation 1584 through any ofthe methods described herein. For example, the electrical power 1582 maybe feed at a high voltage, for example 132 kV, to a transformer 86 andlet down to a lower voltage, for example 6600 V, before being fed to anelectrical resistance heater element located in a heater well 1587located in the subsurface formation 1584. In this way all or a portionof the power required to heat the subsurface formation 1584 may begenerated from the non-condensable portion of the produced fluids 1585.Excess gas, if available, may be exported for sale.

Produced fluids from in situ oil shale production contain a number ofcomponents which may be separated in surface facilities. The producedfluids typically contain water, noncondensable hydrocarbon alkanespecies (e.g., methane, ethane, propane, n-butane, isobutane),noncondensable hydrocarbon alkene species (e.g., ethene, propene),condensable hydrocarbon species composed of (alkanes, olefins,aromatics, and polyaromatics among others), CO₂, CO, H₂, H₂S, and NH₃.

In a surface facility, condensable components may be separated fromnon-condensable components by reducing temperature and/or increasingpressure. Temperature reduction may be accomplished using heatexchangers cooled by ambient air or available water. Alternatively, thehot produced fluids may be cooled via heat exchange with producedhydrocarbon fluids previously cooled. The pressure may be increased viacentrifugal or reciprocating compressors. Alternatively, or inconjunction, a diffuser-expander apparatus may be used to condense outliquids from gaseous flows. Separations may involve several stages ofcooling and/or pressure changes.

Water in addition to condensable hydrocarbons may be dropped out of thegas when reducing temperature or increasing pressure. Liquid water maybe separated from condensed hydrocarbons via gravity settling vessels orcentrifugal separators. Demulsifiers may be used to aid in waterseparation.

Methods to remove CO₂, as well as other so-called acid gases (such asH₂S), from produced hydrocarbon gas include the use of chemical reactionprocesses and of physical solvent processes. Chemical reaction processestypically involve contacting the gas stream with an aqueous aminesolution at high pressure and/or low temperature. This causes the acidgas species to chemically react with the amines and go into solution. Byraising the temperature and/or lowering the pressure, the chemicalreaction can be reversed and a concentrated stream of acid gases can berecovered. An alternative chemical reaction process involves hotcarbonate solutions, typically potassium carbonate. The hot carbonatesolution is regenerated and the concentrated stream of acid gases isrecovered by contacting the solution with steam. Physical solventprocesses typically involve contacting the gas stream with a glycol athigh pressure and/or low temperature. Like the amine processes, reducingthe pressure or raising the temperature allows regeneration of thesolvent and recovery of the acid gases. Certain amines or glycols may bemore or less selective in the types of acid gas species removed. Sizingof any of these processes requires determining the amount of chemical tocirculate, the rate of circulation, the energy input for regeneration,and the size and type of gas-chemical contacting equipment. Contactingequipment may include packed or multi-tray countercurrent towers.Optimal sizing for each of these aspects is highly dependent on the rateat which gas is being produced from the formation and the concentrationof the acid gases in the gas stream.

Acid gas removal may also be effectuated through the use of distillationtowers. Such towers may include an intermediate freezing section whereinfrozen CO₂ and H₂S particles are allowed to form. A mixture of frozenparticles and liquids fall downward into a stripping section, where thelighter hydrocarbon gasses break out and rise within the tower. Arectification section may be provided at an upper end of the tower tofurther facilitate the cleaning of the overhead gas stream.

The hydrogen content of a gas stream may be adjusted by either removingall or a portion of the hydrogen or by removing all or a portion of thenon-hydrogen species (e.g., CO₂, CH₄, etc.) Separations may beaccomplished using cryogenic condensation, pressure-swing ortemperature-swing adsorption, or selective diffusion membranes. Ifadditional hydrogen is needed, hydrogen may be made by reforming methanevia the classic water-shift reaction.

In producing hydrocarbons from a shale oil field, it may be desirable tocontrol the migration of pyrolyzed fluids through the use of injectionwells, particularly around the periphery of the field. Such wells mayinject water, steam, CO₂, heated methane, or other fluids to drivecracked kerogen fluids towards production wells. In other arrangements,physical barriers may be placed around the area of the organic-rich rockformation under development. One example of a physical barrier involvesthe creation of freeze walls.

Freeze walls are formed by circulating refrigerant through peripheralwells to substantially reduce the temperature of the rock formation. Inone aspect, ice is formed in pore spaces. This, in turn, prevents themigration of fluids across the freeze walls through any existingchannels in the formation. Additionally, the freeze wall may prevent thepyrolyzation of kerogen present at the periphery of the field. Theprevention of fluid migration is particularly important if the formationis connected to a ground water source.

The use of subsurface freezing to stabilize poorly consolidated soils orto provide a barrier to fluid flow is known in the art. ShellExploration and Production Company has discussed the use of freeze wallsfor oil shale production in several patents, including U.S. Pat. Nos.6,880,633 and 7,032,660. Shell's '660 patent uses subsurface freezing toprotect against groundwater flow and groundwater contamination during insitu shale oil production.

Additional patents that disclose the use of so-called freeze walls areU.S. Pat. Nos. 3,528,252; 3,943,722; 3,729,965; 4,358,222; and4,607,488. WO Pat. No. 98996480 is also of interest. Also, K. Stoss andJ. Valk, “Uses and Limitations of Ground Freezing with Liquid Nitrogen”,Engineering Geology, 13, pp. 485-494 (1979); and R. Rupprecht,“Application of the Ground-Freezing Method to Penetrate a Sequence ofWater-Bearing and Dry Formations—Three Construction Cases”, EngineeringGeology, 13, pp. 541-546 (1979) discusses subsurface freezingtechniques. The disclosures of these patents and the technical articleare hereby incorporated by reference in their entireties.

The use of freeze wells to form a barrier around an in situ pyrolysiszone has also been described by Ljungstrom in U.S. Pat. No. 2,777,679.Vinegar, et al. more recently described a similar application of freezewalls. See, for example, U.S. Pat. Nos. 7,077,198; and 6,854,929.

Various means of using forming freeze walls have been previouslydisclosed. For example, U.S. Pat. No. 4,860,544, Kriet, et al.,described a method for creating a closed, flow-impervious cryogenicbarrier by extending an array of freeze wells at angles into the earthso that an inverted tent-like frozen structure is formed. Also, U.S.Pat. No. 3,267,680 described forming a freeze wall of increasedmechanical strength by using a series of freeze wells that alternate inangle. Specifically every other well is vertical while the intermediatewells are 3-30° off-vertical.

Use of a single downhole expansion valve in a freeze well has beendisclosed for certain specific applications, although not for forming afreeze wall. In U.S. Pat. No. 3,004,601 Bodine described using a coolingwell with a downhole expansion valve specifically to reduce thetemperature of subsurface oil. The purpose of reducing the temperatureof the subsurface oil was to increase gas solubility and to preventnatural gas bubbles from hindering oil flow. Ralstin and Heathman inU.S. Pat. No. 3,559,737 described forming an underground gas storagechamber by sealing caprock fractures of a permeable formation usingcryogenic cooling. Use of a downhole throttle is disclosed as a means ofcooling.

Use of specific slurries as cooling fluids has been disclosed forapplication in methods to form freeze walls. For example, Schroeder inU.S. Pat. No. 3,372,550 described a method for designing a freeze wellwhich can create an ice wall with greater strength at the bottom than atthe top. The method requires injection of refrigerant into the well atmultiple points. Schroeder disclosed the use of a carbon dioxide slurryas a cooling fluid. Also, In U.S. Pat. No. 3,271,962, Dahms, et aldescribed a method of freezing the earth around a mine shaft usingmultiple freeze wells connected to a common subterranean cavity. Use ofbrines or partially frozen brine slurries as cooling fluids isdisclosed.

The methods disclosed in the cited references generally use a workingfluid (e.g., brine or liquid nitrogen) that is injected into variouswells. The working fluid is circulated through the individual freezewells in order to thermally chill the surrounding formation. Such wellsoftentimes cause native water in the formation and adjacent the wells tofreeze.

It is desirable to improve upon subsurface freezing methodologies to aidin the cooling of organic-rich rock within a subsurface formation. Thisis particularly true with respect to hydrocarbon development areas thatrequire the pyrolyzation of an organic-rich rock formation. Suchimprovements are for the purpose of generating freeze zones deepunderground. Alternatively, such improvements may be in the area of thecooling characteristics of the working fluid. Alternatively still,improvements may be in the area of increasing the subsurface freezingrate.

FIG. 6 is a cross-sectional view of a portion of a hydrocarbondevelopment area 600. The development area 600 represents a surface 602,and a formation 610 below the surface 602. The subsurface formation 610is an organic rich rock formation, such as oil shale. The oil shaleformation 610 comprises kerogen which may be converted to hydrocarbonfluids. The development area 600 is for the purpose of developinghydrocarbons from the subsurface oil shale formation 610.

The formation 610 has a depth “d”. The depth “d” is generally measuredby the distance between the surface 602 and the top of the formation610. In some embodiments, the oil shale formation 610 targeted for insitu pyrolysis or retorting is at a depth greater than 200 feet belowthe surface. In alternative embodiments, the oil shale formation 610targeted for in situ retorting is at a depth greater than 500, 1,000, or1,500 feet below the surface 602, but typically no deeper than 5,000feet. In alternative embodiments, the oil shale formation 610 targetedfor in situ retorting is at a depth between 500 and 4,000 feet;alternatively, between 600 and 3,500 feet; or between 700 and 3,000 feetbelow the surface 602.

The formation 610 may be an oil shale having a very limited permeabilityab initio, e.g., less than 5 millidarcies. In order to develop the oilshale formation 610, it is necessary to pyrolyze the solid hydrocarbons,or kerogen, in the formation 610. This is done by heating the formation610 above a pyrolysis temperature for an extended period of time. Inorder to heat the formation 610 and produce hydrocarbons, a plurality ofheater wells 630 are provided. In the illustrative development area 600,the heater wells 630 are arranged in a plurality of rows, or lineararrays. Each heater well 630 has a wellbore 632 extending down to andcompleted in the formation 610. Each wellbore 632 in the arrangement ofFIG. 6 is substantially vertical. However, the present inventions arenot limited by the nature of the completion or the arrangements for theheater wells 630.

Preferably, the heater wells 630 are designed to provide resistive heatto the formation 610 at a selected temperature. In one aspect, thepyrolyzed oil shale formation 610 will have an average permeability ofgreater than 10 millidarcies after heating. The heater wells 630 may belocated in relatively close proximity, being from 10 feet to up to 300feet in separation. Alternatively, the wellbores may be spaced from 30to 200 feet or from 50 to 100 feet.

Interspersed between the lines of heater wells 630 are production wells640. Each production well 640 has a wellbore 642 extending down to andcompleted in the formation 610. Each production wellbore 642 in thearrangement of FIG. 6 is also substantially vertical. However, thepresent inventions are not limited by the nature of the completion orthe arrangements for the production wells 640. Further, the relativearrangement of heater wells 630 to production wells 640 may be inpolygonal patterns such as a 3-spot pattern or a 5-spot pattern (notshown).

The process of heating an oil shale formation 610 also changes thepermeability of the formation 610. By heating the oil shale andtransforming the kerogen to oil and gas, the permeability is increasedthrough the gradual conversion of kerogen to fluids. Pyrolyzedhydrocarbon fluids migrate in the formation 610 to the wellbores 642 ofthe production wells 640.

It is desirable to contain the migration of pyrolyzed hydrocarbon fluidswithin the development area 600. Therefore, it is desirable to form abarrier to the flow of hydrocarbon fluids, such as a barrier along aperiphery 604 of the shale oil development area 600. Such may be donethrough the completion of “freeze wells” along the periphery 604. In thedevelopment area 600 of FIG. 6, a plurality of freeze wells 620 areseen.

The freeze wells 620 are generally linear along transverse edges of theperiphery 604. However, the present inventions are not limited to theplacement or arrangement of the freeze wells 620. What is important isthat the freeze wells 620 operate to prevent the flow of fluids from thedevelopment area 600 and across the periphery 604 or other designatedboundary. Such fluids may be groundwater, pyrolyzed hydrocarbon fluids,or other fluids. This may be done by bringing the temperature of theformation 610 to a point where in situ fluids around the periphery 604are frozen. At a minimum, this is done by maintaining a portion of theformation 610 at a temperature below the pyrolysis point, such as below225° C. to keep the kerogen in a solid state. Thus, the term “freezewell” does not require that the well 620 actually create a frozenboundary, but only maintain a substantially solid boundary with very lowpermeability. Preferably though, the freeze wells 620 maintain theperiphery 604 (or other barrier area) of the formation 610 below thefreezing point of the in situ water, that is, approximately 0° C.

It is also noted from FIG. 6 that each freeze well 620 has a wellbore622. The wellbores 622 are completed at or below the depth of theformation 610. In the arrangement shown in FIG. 6, each freeze wellwellbore 622 is substantially vertical. However, the present inventionsdo not preclude the use of deviated, or even horizontally completed,wellbores 622.

Although not shown in FIG. 6, the freeze wells 620 operate together toform a freeze wall around the periphery 604 of the development area 600.The integrity of the freeze walls may be evaluated by placing monitoringwells outside of the freeze wall boundaries, or periphery 604. Fluidsamples, particularly water samples, may be periodically collected andanalyzed for unacceptable concentrations of various chemicals, e.g.,metal species, acidic species, sulfur species, or hydrocarbons. Variousdownhole measurements may also be used instead of or complimentary tofluid sampling. Downhole measurements may include compositionalmeasurements, pH measurements, temperature measurements, or electricalresistivity measurements.

FIG. 7 is a cross-sectional view of a wellbore 700 for a freeze well620, in one embodiment. The wellbore 700 is completed at the level of anorganic-rich rock formation 610. The illustrative wellbore 700 issubstantially vertical. In order to form the wellbore 700, a bore isformed through the earth surface 602 and into the subterranean earth 702using any known drilling procedure or technique. In order to isolate thebore from the surrounding subterranean earth 702, a string of casing 706is hung or otherwise positioned adjacent the surrounding subterraneanearth 702. The casing 706 is preferably cemented in place with a curablematerial such as cement 704. The casing 706 and cement 704 preferablyare not perforated at any point, even adjacent the formation 610.

Next, an elongated tubular member 708 is hung or otherwise placed withinthe wellbore 700. The elongated tubular member 708 preferably extendsfrom the earth surface 602 down to and through the subsurface formation610. The elongated tubular member 708 defines a bore 705 which receivesa cooling fluid. The cooling fluid serves as a working fluid fordistributing cold energy to the subsurface formation 610. The term “coldenergy” refers to the difference in enthalpy between the cooling fluidand the warmer surroundings to be cooled. The cooling fluid travelsalong the direction indicated by arrows 605.

The elongated tubular member 708 also defines an annular region 707 withthe surrounding casing 706. Arrows 605 further indicate that the coolingfluid is circulated down the bore 705 of the tubular member 708 and thenback up the annular region 707 to the earth surface 602. The coolingfluid is captured at a wellhead and optionally recirculated.

In one aspect, the cooling fluid may be chilled prior to injection intothe wellbore 700. For example, a surface refrigeration system (notshown) may be used to chill the cooling fluid. In another aspect, thesurface refrigeration system is replaced by a gas compression system(not shown) and a downhole expansion valve 720. Use of a downholeexpansion valve 720 to cause cooling of the circulating fluid has thebenefit of removing or significantly reducing “cold energy” losses tothe overburden while transporting the cooling fluid from the surface 602to the subsurface formation 610. Alternatively, use of a downholeexpansion valve 720 removes the need for wellbore insulation in theoverburden region.

Gas is compressed in the gas compression system at the surface 602. Thecompressed gas is then cooled to near-ambient temperature via air orwater cooling. In some cases, the gas may be further cooled viarefrigeration. None, some, or all of the fluid may be in a condensedstate after the cooling steps. The cooling fluid is then sent down thebore 705 of the elongated tubular member 708, and through the expansionvalve 720. This causes the fluid to cool via the Joule-Thomson effect.

Preferably, the expansion valve 720 is proximate to the subsurfaceformation 610. In the wellbore 700, the expansion valve 720 is at thetop of the formation 610. The cooling fluid is allowed to absorb heatfrom the surrounding formation 610, which in turn leads to ice formationwithin the subsurface formation 610.

It is known that certain compressed gases when expanded through a valveundergo significant cooling. Use of a downhole expansion valve togenerate the primary cooling effect has the benefit that a cold fluiddoes not need to flow from the surface 602 down to the depth of interest610. Flowing a cooling fluid from the surface 602 would most likelyresult in a loss of cold energy due to conductive losses to thesurrounding earth 702 during transit to the depth of interest. Theselosses can be quite significant if the target zone is deep. For example,in situ oil shale production target zones may be at a depth of 300 feet,1,000 feet, 2,000 feet or more. Cold losses can be reduced through theuse of insulation but this may increase well costs and reducecross-sectional area available for fluid flow.

Insulation may be placed along all or a portion of the elongated tubularmember 708 to reduce cross heat exchange between the upward and downwardflows. Cross heat exchange reduces the length of the effective coolingzone since returning spent fluid warms the injected cooling fluid. Ifneeded, insulation is preferably placed only below the expansion valve720 since cross heat exchange can be beneficial above the valve 720 byallowing cool returning fluid to pre-cool the injected fluid prior to itpassing through the expansion valve 720.

FIG. 8 is a cross-sectional view of the expansion valve 720. This is anenlarged view of the expansion valve 720 used in the wellbore 700 ofFIG. 7. It can be seen that the expansion valve 720 has wall 728 with anupper threaded end 724 and a lower threaded end 726. The threaded ends724, 726 enable the expansion valve 720 to be threaded in series withthe elongated tubular member 708. The valve 720 defines a bore 725 whichis in fluid communication with the bore 705 of the elongated tubularmember 708.

The bore 725 of the valve 720 defines inner diameters. At the upper end724 of the valve 720, an inner diameter 732 is provided which generallyconforms to the inner diameter of the bore 705. However, the innerdiameter 732 tapers to a smaller inner diameter 736 at the bottom 726 ofthe expansion valve 720. The effect is to create a constriction on thebore 705 of the elongated tubular member 708 in order to provide theJoule-Thompson effect.

FIG. 9 is a cross-sectional view of an alternate arrangement for anexpansion valve 720′ as might be used in the wellbore 700 of a freezewell 622. It can be seen that the expansion valve 720′ also has wall728′ with an upper threaded end 724′ and a lower threaded end 726′. Thethreaded ends 724′, 726′ again enable the expansion valve 720′ to bethreaded in series with the elongated tubular member 708. The valve 720′defines a bore 725′ which is in fluid communication with the bore 705 ofthe elongated tubular member 708.

The bore 725′ of the valve 720′ defines inner diameters. At the upper724 and lower 726′ ends of the valve 720′, an inner diameter 732′, 736′is provided. Those inner diameters 732′, 736′ generally conform to theinner diameter of the bore 705. However, an intermediate constrictedportion 722′ of the valve 720′ has a decreased inner diameter 737′. Theeffect is to create a constriction on the bore 705 of the elongatedtubular member 708 in order to provide the Joule-Thompson effect.

It is noted that other arrangements of an expansion valve 720 may beemployed for the methods and wellbores herein. The valves 720, 720′ aremerely illustrative.

Preferably, the cooling fluid is at a temperature of about −20° F. to−120° F. after passing through the expansion valve 720. More preferably,the cooling fluid is at a temperature of about −20° F. to −80° F. afterpassing through the expansion valve 720. More preferably still, thecooling fluid is at a temperature of about −30° F. to −60° F. afterpassing through the expansion valve 720.

Preferably, the cooling fluid is at a pressure of about 100 psia to2,000 psia before passing through the expansion valve 720, and about 25psia to about 500 psia after passing through the expansion valve 720.More preferably, the cooling fluid is at a pressure of about 200 psia to800 psia before passing through the expansion valve 720, and about 40psia to about 200 psia after passing through the expansion valve 720.

As noted, the expansion valve 720 may be placed in the wellbore of afreeze well 620 at different locations. In addition, more than oneexpansion valve 720 may be used. FIG. 10 is a cross-sectional view of awellbore 1000 for a freeze well 620, in an alternate embodiment. In thiswellbore 1000, two expansion valves 720U and 720L are placed at thelevel of an organic-rich rock formation 610. Expansion valve 720U isplaced proximate the top of the formation 610, while expansion valve720L is placed proximate the bottom of the formation 610. Thus,expansion valve 720U is an upper valve, while expansion valve 720L is alower valve.

The use of two expansion valves 720U and 720L permits a more uniformcooling temperature across the formation 610 than possible with a singleexpansion valve. This in turn can lead to a more uniform freeze wallacross the thickness of the formation 610 and, thus, reduce the energyneeded to reach a desired thickness throughout.

In operation, a first temperature drop is accomplished as the workingfluid moves through the first expansion valve 720U. The working fluidthen imparts cold energy to the subsurface formation 610 on the waydown. A second temperature drop is then accomplished as the workingfluid moves through the second expansion valve 720L. The working fluidmay then impart additional cold energy to the subsurface formation 610on the way up.

It is noted that the relative placement of valves 720U and 720L is amatter of designer's choice. In addition, the sizing of the innerdiameters of the expansion valves 720U, 720L is a matter of designer'schoice. The placement and the sizing of the expansion valves 720U, 720Lmay be adjusted to provide for selective pressure drops. In one aspect,the cooling fluid is at a pressure of about 500 psia to 2,000 psiabefore passing through the second expansion valve 720L, and about 25psia to about 500 psia after passing through the second expansion valve720L.

For the case of a single downhole expansion valve, the cooling fluid ispreferably at a pressure of about 100 psia to 2,000 psia before passingthrough the expansion valve 720. More preferably, the cooling fluid isat a pressure of about 200 psia to 800 psia. For the case of dualdownhole expansion valves such as 720U and 720L, preferably the coolingfluid is at a pressure of about 800 psia to 4,000 psia before passingthrough the first expansion valve 720U, about 100 psia to about 800 psiaafter passing through the first expansion valve 720U, and about 25 to100 psia after passing through the second expansion valve 720L. Morepreferably, the cooling fluid is at a pressure of about 800 psia to2,000 psia before passing through the first expansion valve 720U, about100 psia to about 500 psia after passing through the first expansionvalve 720U, and about 25 psia to about 100 psia after passing throughthe second expansion valve 720L.

In one aspect, a ratio of entry pressure-to-exit pressure across theexpansion valves is provided. For instance, the ratio of entrypressure-to-exit pressure across the first expansion valve and the ratioof entry pressure-to-exit pressure across the second expansion value areequal to within a factor of about three.

In the wellbore 1000 of FIG. 10, both expansion valves 720U and 720Lcreate a Joule-Thompson effect for the cooling fluid within the bore 705of the elongated tubular member 708. However, it is feasible to provideone or both of the pressure drops outside of the bore 705. This isdemonstrated in FIG. 11.

FIG. 11 is a cross-sectional view of a wellbore 1100 for a freeze well620 in yet an additional embodiment. In this arrangement 1100, twoexpansion valves 720I and 720O are again placed proximate the level ofthe organic-rich rock formation 610. However, one valve 720I is alongthe inner diameter (or bore 705) of the elongated tubular member 708,while the other valve 720O is along the outer diameter (or annularregion 707) of the tubular member 708.

The first or inner expansion valve 720I creates a pressure drop withinthe bore 705, and may be in the form of valves 720 or 720′. However, thesecond or outer expansion valve 720O creates a pressure drop outside ofthe bore 705. This may be in the form of a clamped circular device or atubular member with an enlarged outer diameter.

In the wellbore arrangements 700, 1000 and 1100, the cooling fluid ispumped under pressure down the bore 705, to the bottom 710 of thewellbore, and then back up the annular region 707. The cooling fluid isthen recaptured at the surface 602. As noted, the cooling fluid may berechilled in a refrigeration system and then again pumped through thegas compression system. In these embodiments, it is optional to provideinsulation to the elongated tubular member 708 above the targetedsubsurface formation 610.

In an alternate wellbore arrangement, a U-tube may be used as theelongated tubular member. FIG. 12 presents a cross-sectional view of awellbore 1200 for a freeze well 620, in an alternate embodiment. Thewellbore 1200 is generally in accord with wellbore 700 of FIG. 7.However, in this arrangement the elongated tubular member is a U-tube1208. The U-tube 1208 provides a closed system through which the coolingfluid flows. The cooling fluid flows into a bore 1205 in the U-tube 1208in accordance with arrows 605. The cooling fluid remains in the bore1205 flowing both downward to the subsurface formation 610 and back upto the surface 602.

An expansion valve 1220 is once again employed in the wellbore 1200. Theexpansion valve 1220 may use one of the configurations of FIG. 8 or 9,or any other embodiment that will provide a Joule-Thompson effect. Theexpansion valve 1220 is preferably placed at the top of the formation610 so that the cooling fluid flows through the valve 1220 prior to orjust at the point of reaching the subsurface formation 610. However, theembodiment of FIG. 12 is not limited to the exact placement of theexpansion valve 1220. For instance, the expansion valve 1220 may bepositioned in the U-tube 1208 at a point in which the cooling fluid istraveling back up to the surface 602.

It is also noted that in the wellbore 1200 of FIG. 12, no casing orcement are used to isolate the earth 702. Instead, packing, such as sandor gravel are placed in the annular region 707 between the U-tube 1208and the formation 610. The sand aids conductive heat transfer.

In any of the wellbore arrangements 700, 1000, 1100, 1200, the returncooling fluid may still be relatively cold, at least compared to ambientconditions. This fluid could be used in connection with a refrigerationsystem at the surface 602. Refrigeration of working facilities could beprovided so that the cold energy remaining in the return fluid is notlost. However, it is preferred that the fluid returning to the surfacebe near ambient temperature so as to maximize its loss of cold energy tothe formation 610 itself.

When using downhole expansion valves, a number of fluids are suitablefor the freeze wells 620. Preferably, the fluid returns largely in itsvapor state. This reduces head losses in the return conduit and, thus,increases the achievable pressure differential across the expansionvalve 720. It is additionally preferable that any vaporizable liquidsgenerated through the expansion valve 720 be largely vaporized in thesubsurface formation 610. The latent heat of vaporization of theseliquids may constitute a large portion of the available cold energy totransfer into the formation 610.

It is also preferable that the temperature of the expanded fluidimmediately exiting the valve 720 be below about 0° F., and morepreferably, be below about −30° F. This provides a sizeable temperaturedifferential to drive heat transfer and to provide a sizeable thermalcapacity to absorb heat from the surrounding formation 610 into thecooling fluid. Suitable fluids may include C₂-C₄ hydrocarbons (e.g.,ethane, ethylene, propane, propylene, isobutane, and n-butane) ormixtures containing a majority of one or more of these components. Othersuitable components may include refrigerant halogenated hydrocarbons,carbon dioxide, and ammonia. The specific compositional choice for acooling fluid depends on a number of factors including workingpressures, available pressure drop through the valve, thermodynamicbehavior of the fluid, temperature limits of the metallurgy of theconduits, safety considerations, and cost/availability considerations.

In another embodiment, all of the refrigeration is done in a surfacefacility, with the working fluid being a slurry consisting of apartially frozen liquid. One method of generating a cold slurry is touse a continually scraped heat exchanger to cool and partially freezethe fluid. The cold slurry is circulated through the freeze wells 620 tochill the subsurface formation 610. Use of a partially frozen liquid asa heat transfer medium can be beneficial since the latent heat ofmelting adds significantly to the cooling capacity of the fluid on avolume basis. To be most effective, the freezing point of the liquidshould be below the freezing point of water. Preferably, the freezingpoint is below about 0° F., and more preferably be below about −30° F.This provides a sizeable temperature differential to drive heat transferand to provide a sizeable thermal capacity to absorb heat from thesurrounding formation 610 into the cooling fluid. Suitable liquids mayinclude partial frozen salt-water mixtures (brines), alcohols,alcohol-water mixtures, or glycol-water mixtures.

Suitable brines may include inorganic salts such as sodium chloride,calcium chloride, or lithium chloride. The brines may also include saltsof certain organic acids such as potassium formate, potassium acetate,potassium citrate, ammonium formate, ammonium acetate, ammonium citrate,sodium citrate, sodium formate, or sodium acetate. Applicable alcoholsmay include methanol, ethanol, and isopropanol. Applicable glycolsinclude monoethylene glycol, diethylene glycol, and propylene glycol.

Preferably, the working fluid is of low viscosity and of low corrosivityto the conduits. In certain cases, eutectic mixtures (i.e., minimumfreezing point compositions) may be particularly appealing to providelow temperatures. For example, pure methanol freezes at −98° F., but abinary mixture of 83 wt % methanol and 17 wt % water freezes at −129° F.In other cases slurries with freezing points between −20° F. and −40° F.may be appealing so to permit safe use of standard carbon steel (whichbecomes brittle at lower temperatures) while still maintainingsignificant cooling capacity. Such fluids may include brines,water-alcohol mixtures, or water-glycol mixtures. For example a 50-50 wt% water-ethanol mixture has a freezing point of −38° F. and a densitywhere ice is nearly neutrally buoyant. Neutrally buoyant ice may aidflowability of the slurry.

Alternative working fluids may include light liquid hydrocarbon species(e.g., C₇-C₁₄) and mixtures, including commonly available mixtures suchas gasoline and diesel. These hydrocarbon fluids can freeze out waxes atsubzero temperatures and thus form partially frozen slurries. Thehydrocarbon fluid composition, particularly n-paraffin content, can bevaried to tailor its freezing behavior over a wide range oftemperatures.

It can be seen that various embodiments of a wellbore for a freeze wellhave been disclosed. The cooling wellbore is for the purpose of loweringthe temperature of a subsurface formation 610. The wellbore is completedat or below a depth of the subsurface formation 610, and in one aspectincludes an elongated tubular member such as tubular member 708, and afirst expansion valve such as valve 720. The first expansion valve is influid communication with the elongated tubular member. A cooling fluidis directed through the elongated tubular member and the first expansionvalve in order to cool the subsurface formation 610.

In one aspect, the elongated tubular member is a U-tube such as tubularmember 1208. The first expansion valve may be positioned in the tubularmember at or above a depth of the subsurface formation 610.Alternatively, the first expansion valve may be positioned in thetubular member proximate a lower depth of the subsurface formation.Alternatively, the first expansion valve may be positioned in thetubular member proximate an upper depth of the subsurface formation.

In one embodiment, the wellbore further comprises an annular regionformed between the elongated tubular member and a diameter of thewellbore. The cooling fluid may be circulated through the tubularmember, to the subsurface formation, and back up the wellbore throughthe annular region.

Various cooling fluids may be used. In one aspect, the cooling fluidcomprises a gas and remains in a substantially gaseous state when passedthrough the first expansion valve. Alternatively, the cooling fluid maybe injected in a gaseous state, but a portion of the cooling fluidcondenses from a gas to a liquid state as the cooling fluid is passedthrough the first expansion valve.

The injected cooling fluid may comprise at least of 50 mol. percent ofpropane, propylene, ethane, ethylene, or a mixture thereof.Alternatively, the cooling fluid may comprise at least of 80 mol.percent of propane, propylene, ethane, ethylene, isobutane, or a mixturethereof. Alternatively, the injected cooling fluid may comprise at leastof 50 mol. percent of a halogenated hydrocarbon. Alternatively still,the cooling fluid may comprise at least of 80 mol. percent of ahalogenated hydrocarbon.

The cooling fluid may be chilled prior to injection into the tubularmember. For instance, the cooling fluid may be chilled below ambient airtemperature prior to injection into the tubular member. In any instance,the cooling fluid may be injected into the subsurface formation at acontrolled rate such that the cooling fluid flows through the firstexpansion valve and adjacent the subsurface formation, and then leavesthe subsurface formation with no more than 20 wt. % in a liquid state.Alternatively, the cooling fluid may be injected into the subsurfaceformation at a controlled rate such that the cooling fluid flows throughthe first expansion valve and adjacent the subsurface formation, andthen leaves the subsurface formation with no more than 5 wt. % in aliquid state.

In one aspect, the cooling fluid is a partially frozen salt-watermixture. The salt in the salt-water mixture may be, for example, NaCl orCaCl₂. The cooling fluid may alternately define a partially frozenalcohol-water mixture. The alcohol may be, for example, methanol orethanol. In another aspect, the cooling fluid may define a partiallyfrozen glycol-water mixture. The glycol may be, for example, MEG, DEG,or propylene glycol. In another aspect, the cooling fluid may define ahydrocarbon mixture comprised of greater than 50 mol. percent carbonmolecules of C₇, C₈, C₉, C₁₀, C₁₁, C₁₂, C₁₃, C₁₄, or mixtures thereof.

The cooling wellbore may be placed at various positions relative to theshale oil development area. Preferably, one or more wellbores are formedoutside of or along the periphery of the area under shale oildevelopment.

In view of the various wellbore arrangements discussed above, variouscorresponding methods for lowering the temperature of a portion of asubsurface formation 610 may be provided. In practicing such methods, awellbore is completed at or below a depth of the subsurface formation610. The wellbore (such as wellbore 700 or 1200, for example) has anelongated tubular member (such as tubular member 708 or 1208, forexample) for receiving a cooling fluid and for transporting it downholeto the subsurface formation 610. The wellbore also has a first expansionvalve (such as valve 720 or 720′, for example) in fluid communicationwith the tubular member through which the cooling fluid flows. Themethod then includes the steps of injecting the cooling fluid underpressure into the wellbore, and expanding the cooling fluid across thefirst expansion valve. In this way, the temperature of the cooling fluidis reduced. The temperature of the surrounding formation 610 is thenlikewise reduced through thermal convection, or the transfer of “coldenergy.”

It is preferred that the subsurface formation is an oil shale formation.The oil shale formation is part of a development area for convertingkerogen to shale oil, or hydrocarbons. The wellbore may be placed atvarious positions relative to the shale oil development area.Preferably, one or more wellbores are formed outside of or along theperiphery of the area under shale oil development. An example of such adevelopment area has been shown and described at 600 in FIG. 6.

In one aspect, the elongated tubular member is a U-tube, such as U-tube1208. In this instance, the method further includes the step ofcirculating the fluid into the U-tube, down to the subsurface formation610, and back up to the surface 602. The first expansion valve (such asvalve 1220) may be positioned in the wellbore such that the coolingfluid flows through the first expansion valve upon or before reachingthe depth of the subsurface formation 610. The first expansion valve maybe positioned along the tubular member proximate an upper depth of thesubsurface formation, or elsewhere along the formation. For instance,the first expansion valve may be positioned along the tubular member ata depth of about 300 to 600 feet below the surface. Alternatively, thefirst expansion valve may be positioned so that the cooling fluid flowsthrough the first expansion valve en route back up to the surface 602.

In one embodiment, the wellbore further comprises an annular region(such as region 707) formed between the elongated tubular member and adiameter of the wellbore. In this instance, the method may furtherinclude the step of circulating the fluid through the tubular member, tothe completion depth, and back up the wellbore through the annularregion. The cooling fluid may flow through the first expansion valveupon or before reaching the depth of the subsurface formation. Forinstance, the first expansion valve may be positioned along the tubularmember proximate an upper depth of the subsurface formation.

In another embodiment, the elongated tubular member is a U-tubecomprising a downward portion through which the cooling fluid flows tothe subsurface formation, and an upward portion through which thecooling fluid flows back to the surface. Preferably, the downwardportion is insulated above the subsurface formation. In this embodiment,the wellbore may further include a second expansion valve. The secondexpansion valve is in fluid communication with the tubular member. Afirst pressure drop takes place through the first expansion valve, and asecond pressure drop takes place through the second expansion valve. Inthis instance, the method further comprises expanding the cooling fluidacross the second expansion valve, thereby reducing the temperature ofthe cooling fluid. In this way, the cooling fluid flows through thesecond expansion valve to further cool the subsurface formation.

In one aspect, the elongated tubular member is a U-tube. The coolingfluid flows through the first expansion valve upon or before reachingthe depth of the subsurface formation. The cooling fluid further flowsthrough the second expansion valve at or after reaching the depth of thesubsurface formation.

Preferably, the subsurface formation holds in situ water. Further, thecooling fluid cools the subsurface formation to a sufficient extent tofreeze at least a portion of the in situ water. In one aspect, themethod further includes the step of injecting low salinity water into atleast a portion of the subsurface formation to reduce the naturalsalinity of the in situ water and to raise the freezing temperature ofthe in situ water.

Another method for lowering the temperature of a subsurface formation isprovided herein. Generally, the method comprises the step of injecting acooling fluid at a first temperature into a wellbore. Here, the wellboreis completed at or below a depth of the subsurface formation. Thetemperature of the cooling fluid is then lowered after it has enteredthe wellbore. The cooling fluid is then passed at the lower temperaturethrough the wellbore at a depth of the subsurface formation. Finally,the cooling fluid is circulated back to the surface.

The wellbore may comprise an elongated tubular member that receives thecooling fluid en route to the subsurface formation. The wellbore mayfurther comprise an expansion valve in fluid communication with thetubular member through which the cooling fluid flows to cool the coolingfluid to the lower temperature.

Another method for lowering the temperature of a subsurface formation isprovided herein. This method includes the step of injecting a coolingfluid under pressure into a wellbore. The cooling fluid comprises aslurry having particles of frozen material. Use of a slurry can have thebenefit of significantly increasing the “cold energy” carried by thecooling fluid per mass of fluid. Moreover, a slurry can maintain arelatively constant temperature even as it loses “cold energy” due tothe latent heat of fusion of the solids. The wellbore is completed at orbelow a depth of the subsurface formation. The wellbore has a boreformed through the subsurface formation that defines a diameter. In thiscase no downhole expansion valve is required. Use of a slurry can havethe extra benefit or removing or reducing the need for insulationbetween the upward and downward flows since the slurry can be maintainedat a relatively constant temperature as long as frozen solids are stillpresent.

In one aspect of this additional embodiment, the wellbore includes anelongated tubular member such as tubular member 708. The tubular memberreceives the cooling fluid en route to the subsurface formation 610. Theelongated tubular member may be a U-tube such as tubular member 1208. Inthis instance, the method further includes circulating the cooling fluidinto the U-tube, to the completion depth, and back to the surface 602.

The wellbore may further comprise an annular region (such as annularregion 707) formed between the elongated tubular member and the diameterof the wellbore. In this instance, the method may further includecirculating the fluid into the tubular member, down to the completiondepth, and back up the wellbore through the annular region.

In another aspect of this additional embodiment, the wellbore mayfurther comprise an expansion valve. The expansion valve is in fluidcommunication with the tubular member through which the cooling fluidflows to cool the subsurface formation. The expansion valve may bepositioned along the tubular member proximate an upper depth of thesubsurface formation. Alternatively, the expansion valve may bepositioned intermediate the subsurface formation.

Various cooling fluids may be used. In one aspect, the cooling fluid isa partially frozen salt-water mixture. The salt in the salt-watermixture may be, for example, NaCl or CaCl₂. The cooling fluid mayalternately define a partially frozen alcohol-water mixture. The alcoholmay be, for example, methanol or ethanol.

In another aspect, the cooling fluid may define a partially frozenglycol-water mixture. The glycol may be, for example, MEG, DEG, orpropylene glycol. In another aspect, the cooling fluid may define ahydrocarbon mixture comprised of greater than 50 mol. percent carbonmolecules of C₇, C₈, C₉, C₁₀, C₁₁, C₁₂, C₁₃, C₁₄, or mixtures thereof.

The particles of frozen material used in this additional embodiment maybe less than 50 microns in size. Some or all of the particles may beless than 10 microns in size.

Preferably, the subsurface formation holds in situ water. Further, thecooling fluid cools the subsurface formation to a sufficient extent tofreeze at least a portion of the in situ water. In one aspect, themethod further includes the step of injecting low salinity water into atleast a portion of the subsurface formation to reduce the naturalsalinity of the in situ water and to raise the freezing temperature ofthe in situ water.

Another method for lowering the temperature of a subsurface formation isalso provided herein. The method includes the step of completing a firstinjection well, and completing a second injection well adjacent thefirst injection well. A fracturing fluid is injected into the firstinjection well so as to form a fracture at a depth of the subsurfaceformation, thereby providing fluid communication between the first andsecond injection wells. The fracturing fluid preferably comprises aproppant to prop the formation. Once fluid communication is established,a cooling fluid is injected under pressure into the first injectionwell. The cooling fluid is further injected into the fracture so as tolower the temperature of the subsurface formation.

FIG. 13 is a perspective view of a freeze wall 1300 being formed in asubsurface formation 1330 in accordance with this additional method. Afirst injection well 1310 is completed in the formation 1330.Preferably, this first injection well 1310 is completed horizontally.Likewise, a second injection well 1320 is completed adjacent the firstinjection well 1310. Preferably, the second injection well 1320 is alsocompleted horizontally.

The first injection well 1310 and the second injection well 1320 haveeach been perforated. Further, at least one of the injection wells 1310of 1320 has been fractured. In this way, fluid communication isestablished between the first 1310 and second 1320 injection wells inthe formation 1330.

In order to form the freeze wall 1300, a cooling fluid is beingcirculated between the first 1310 and second 1320 injection wells. Arrow1305 indicates a direction of flow of a cooling fluid, in oneembodiment. It can be seen in this arrangement that the cooling fluid isbeing injected into the first injection well 1310, through the formation1330, and into the second injection well 1320. The second injection well1320 receives the cooling fluid via fractures formed in the formation1330. As a result of the circulation of cooling fluid through theformation 1330, the temperature of the formation 1330 is lowered. In oneaspect, the temperature is lowered below the freezing point of water insitu.

It is understood that the well arrangement in FIG. 13 is merelyillustrative. In practice, a number of injection wells 1310, 1320 willbe completed in the formation 1330. The wells 1310, 1320 may becompleted either vertically or in a deviated manner.

For single phase cooling fluids, the fracturing fluid preferablycomprises a proppant to prop the formation. For slurry cooling fluids,the fracturing fluid preferably does not contain a proppant or containsproppant particles which are at least eight times that of the averagesize of the slurry particles.

The benefit of flowing a cooling fluid through a fracture is that theformation of an impermeable frozen zone can be accelerated. For equaltemperature conditions, heat transfer from a planar source (i.e., afracture) is more rapid than from a radial source (i.e., a wellbore) dueto the greater contact area of a planar source. Moreover, the coolingfront propagating from a planar source travels faster than from a radialsource since it does not spread out and disperse nearly as much.Additionally, use of planar fractures can significantly reduce thenumber of wells required to generate a freeze wall as compared to oneformed by a row of unfractured freeze wells.

In one embodiment, at least a portion of the cooling fluid is circulatedback up to the surface through the second injection well. In thismethod, the geomechanical conditions are chosen such that the fractureis substantially vertical. The well from which the fracture is formedmay by substantially vertical or substantially horizontal.

When circulating cold fluids through a formation fracture, the formationis preferably relatively impermeable. This prevents loss of the coldfluid to the formation, and also prevents cooling liquid from mixingwith the native water.

The first injection well 1310 preferably comprises an elongated tubularmember that receives the cooling fluid en route to the subsurfaceformation 1330. The first injection well 1310 may further comprise anexpansion valve in fluid communication with the tubular member throughwhich the cooling fluid flows to cool the subsurface formation 1330. Theexpansion valve may be positioned at various points along the wellbore.In one instance, the expansion valve is positioned along the tubularmember proximate an upper depth of the subsurface formation 1330.

Various cooling fluids may be used as described above. In one aspect,the cooling fluid is a slurry that comprises particles of frozenmaterial. The particles within the cooling fluid may be formed through aprocess of mechanical grinding. The particles may have a compositionthat is different than the cooling fluid. The cooling fluid may be amixture with a composition that is close to the eutectic composition.

In one aspect, the composition of the particles has a freezingtemperature that is higher than the cooling fluid. In this instance, theparticles are formed by rapidly cooling the cooling fluid below thefreezing temperature of the particles, but not below the freezingtemperature of the cooling fluid. In another aspect, the particles areseeded into the cooling fluid in a frozen state. The particles maycomprise a biphasic material having an external portion and an internalportion such that the external portion has a higher freezing temperaturethan the internal portion.

In addition to the above methods, a “freeze wall” may be constructedusing a plurality of freeze wells. In one aspect, this is accomplishedby flowing a cooling fluid through one or more hydraulic fracturesemanating from one or more freeze wells completed in a relativelyimpermeable formation. The hydraulic fractures may be propped orunpropped. The wells may be vertical, deviated, or horizontal. Thehydraulic fractures may extend and connect between wells designated asinjection wells and production wells. Alternatively, the hydraulicfractures may emanate from a dual-completed well wherein injectionoccurs at one point in the wellbore and production from another point inthe same wellbore. In an example of a dual-completed vertical well, thecold fluid may enter the formation near the top of the fracture and beproduced near the bottom of the fracture. This approach has a benefit ofminimizing the number of wells required and more uniformly distributingthe cold to the formation periphery via linear diffusion rather thanradial diffusion.

Preferably, the cold fluid, at least initially, has antifreezeproperties so that any water initially within the fracture does notfreeze and block flow. Examples of such fluids include a brine, alcohol,and glycol. In this way, native water freezes within the periphery ofthe formation and blocks flow. After the immediately surrounding waterhas frozen, an alternate cold fluid may be used which does not haveantifreeze properties. Unless the frozen crystals are very small (e.g.,less than 50 microns, 20 microns, 10 microns, or 5 microns), it isunlikely that it will be practical to pass a slurry through a proppedfracture without experiencing plugging. Generation of slurries with verysmall crystals is possible via several methods. One method is mechanicalgrinding of the slurry. Another method is to promote many small crystalsrather than few large crystals for the same frozen fraction by seedingthe slurry with microparticles prior to the partial freezing step or tocool the fluid extremely rapidly during the partial freezing step. Inany event, it may be beneficial to inject a slurry into the well suchthat the solids completely melt prior to reaching the downhole fracture,thus maintaining the liquid temperature nearly constant during itstransit from the surface.

Yet another method for lowering the temperature of a subsurfaceformation is disclosed herein. This method includes the step ofcompleting a well having fluid communication with the subsurfaceformation at both a first depth and a second lower depth. A fracturingfluid is then injected into the well so as to form a fracture at a depthof the subsurface formation. In this way, fluid communication isprovided between the first and second depths in the well. Then, acooling fluid is circulated under pressure through the well and into thefractures. The cooling fluid flows from one depth to the other, therebylowering the temperature of the subsurface formation.

The well may be completed substantially vertically within the subsurfaceformation. Similarly, the fracture may be substantially vertical.Alternatively, the well may be completed substantially horizontallywithin the subsurface formation. Similarly, the fracture may besubstantially horizontal. The fracture fluid may contain proppant.

FIG. 14 is a cross-sectional view of a dually completed wellbore 1440 asmay be used to practice the above described method. The illustrativewellbore 1400 is completed in a subsurface formation 1410 vertically.The wellbore 1400 is used to form a freeze well in the formation 1410.

It can be seen that the wellbore 1400 is completed at two differentdepths within the formation 1410. The wellbore 1400 is perforated at afirst upper depth 1420, and at a second lower depth 1430. The wellbore1400 is further fractured through the upper depth 1420, the lower depth1430, or both. In this way fluid communication is established across theformation 1410 and between the upper 1420 and lower 1430 depths.

In one aspect, the wellbore 1400 is completed with a string of casing1406. A layer of cement (not shown) may optionally be provided tosupport the casing 1406. An elongated tubular member 1408 is then runinto the wellbore 1406. The tubular member 1408 is hung from the surfaceusing any known completion methods and equipment.

It is noted that an annular region 1407 is formed between the tubularmember 1408 and the surrounding casing 1406 (or formation 1410). Apacker 1417 is set in the annular region 1407 to separate the upper 1420and lower 1430 depths of the wellbore 1400. The packer 1400 is rated towithstand a designated amount of injection pressure.

In operation, a cooling fluid is injected into the annular region 1407in the wellbore 1400. Arrows 1405 denote the direction of fluid travel.The fluid travels down the annular region 1407 and out the perforationsin the upper depth 1420. Fluid movement to the bottom of the wellbore1400 is restricted by the packer 1417. The cooling fluid is able totravel through the formation via formed fractures. Arrows 1405 againdenote the direction of fluid travel. The fluid migrates back into thelower depth 1430 of the wellbore 1400. From there, the fluid moves upthe elongated tubular member 1408 and back up to the surface 1402.

As the cooling fluid travels through the formation 1440, the temperaturein the formation 1440 is lowered. In one aspect, the temperature isreduced to a point at or below the freezing point of water. Because thecooling fluid is actually traveling along a vertical plane formed by thefractures, a vertical wall or barrier is created outward from thewellbore 1400.

In this and any of the other described embodiments, the freezing rate ofthe subsurface formation may be slowed if the freezing point of theambient water is increased. In this respect, if the native water hasdissolved salts (and assuming the formation has permeability), it may bebeneficial to first flush the region with fresh water. This may beaccomplished by injecting low-salinity water through one or more wellslater to be used as cold fluid injection well, or by using dedicatedfreeze barrier wells.

In addition to the above methods for lowering the temperature of asubsurface formation, a method for forming a freeze wall within asubsurface formation is also provided. In one aspect, the methodincludes determining a direction of least principal stress within thesubsurface formation. A plurality of cooling wellbores is then formedalong the direction perpendicular to said direction of least principalstress. A fracturing fluid is injected into at least some of the coolingwellbores so as to form substantially vertical fractures at a depth ofthe subsurface formation, thereby providing fluid communication betweenthe cooling wellbores. Certain of those cooling wellbores are thendesignated as injectors, and certain of them are designated asproducers. A cooling fluid is injected under pressure into the injectorsand further into the fractures so as to lower the temperature of thesubsurface formation. At least a portion of the cooling fluid may thenbe circulated back up to the surface through the producers. In this wayan extended continuous freeze wall can be constructed that will minimizethe number of wells required.

CONCLUSION

The above-described processes may be of merit in connection with therecovery of hydrocarbons in the Piceance Basin of Colorado. Some haveestimated that in some oil shale deposits of the Western United States,up to 1 million barrels of oil may be recoverable per surface acre. Onestudy has estimated the oil shale resource within the nahcolite-bearingportions of the oil shale formations of the Piceance Basin to be 400billion barrels of shale oil in place. Overall, up to 1 trillion barrelsof shale oil may exist in the Piceance Basin alone.

Certain features of the present invention are described in terms of aset of numerical upper limits and a set of numerical lower limits. Itshould be appreciated that ranges formed by any combination of theselimits are within the scope of the invention unless otherwise indicated.Although some of the dependent claims have single dependencies inaccordance with U.S. practice, each of the features in any of suchdependent claims can be combined with each of the features of one ormore of the other dependent claims dependent upon the same independentclaim or claims.

While it will be apparent that the invention herein described is wellcalculated to achieve the benefits and advantages set forth above, itwill be appreciated that the invention is susceptible to modification,variation and change without departing from the spirit thereof.

1. A method of lowering the temperature of a subsurface formation, thesubsurface formation comprising oil shale, and the method comprising:completing a first well; completing a second well adjacent the firstwell; injecting a fracturing fluid into the first well so as to form afracture at a depth of the subsurface formation, thereby providing fluidcommunication between the first and second wells; injecting a coolingfluid under pressure into the first well and into the fracture so as tolower the temperature of the subsurface formation; and circulating atleast a portion of the cooling fluid back up through the second well. 2.The method of claim 1, wherein the fracture is substantially vertical.3. The method of claim 1, wherein the first well comprises an elongatedtubular member that receives the cooling fluid en route to thesubsurface formation.
 4. The method of claim 1, wherein the first wellfurther comprises an expansion valve in fluid communication with thetubular member through which the cooling fluid flows to cool thesubsurface formation.
 5. The method of claim 4, wherein the expansionvalve is positioned along the tubular member proximate an upper depth ofthe subsurface formation.
 6. The method of claim 1, wherein the coolingfluid is a slurry that comprises particles of frozen material.
 7. Themethod of claim 6, wherein the particles are less than 50 microns insize.
 8. The method of claim 6, wherein the cooling fluid defines apartially frozen salt-water mixture, a partially frozen alcohol-watermixture, or a partially frozen glycol-water mixture.
 9. The method ofclaim 8, wherein the particles are formed through a process ofmechanical grinding.
 10. The method of claim 6, wherein the particleshave a composition different than the cooling fluid.
 11. The method ofclaim 10, wherein the composition of the particles has a freezingtemperature that is higher than the cooling fluid, and the particles areformed by rapidly cooling the cooling fluid below the freezingtemperature of the particles, but not below the freezing temperature ofthe cooling fluid.
 12. The method of claim 11, wherein the particles areseeded into the cooling fluid in a frozen state.
 13. The method of claim6, wherein the particles comprise a biphasic material having an externalportion and an internal portion such that the external portion has ahigher freezing temperature than the internal portion.
 14. The method ofclaim 1, wherein the cooling fluid is a liquid comprising an alcohol, analcohol mixture, or an alcohol-water mixture.
 15. The method of claim 1,wherein the cooling fluid is a mixture with a composition that is closeto the eutectic composition.
 16. The method of claim 1, wherein thefracturing fluid comprises a proppant to prop the formation.
 17. Themethod of claim 1, wherein the first well is formed outside of an areaunder shale oil development.
 18. The method of claim 1, wherein thesubsurface formation comprises in situ water, and the cooling fluidcools the subsurface formation sufficient to freeze at least a portionof the in situ water.
 19. The method of claim 18, further comprising thestep of: injecting low salinity water into at least a portion of thesubsurface formation to reduce the natural salinity of the in situ waterand to raise the freezing temperature of the in situ water.
 20. A methodfor forming a freeze wall within a subsurface formation, comprising:determining a direction of least principal stress within the subsurfaceformation; forming a plurality of cooling wellbores along the directionperpendicular to said direction of least principal stress; injecting afracturing fluid into at least some of the cooling wellbores so as toform substantially vertical fractures at a depth of the subsurfaceformation, thereby providing fluid communication between the coolingwellbores; designating certain of the cooling wellbores as injectors andcertain of the cooling wellbores as producers; injecting a cooling fluidunder pressure into the injectors and into the fractures so as to lowerthe temperature of the subsurface formation; and circulating at least aportion of the cooling fluid back up through the producers.